Energy primer

Transcript

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3 E nErgy P rimEr A Handbook of Energy Market Basics November 2015 The Energy Primer is a staff product and does not necessarily reflect the views of the Commission or any Commissioner.

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5 E nErgy rimEr P A Handbook of Energy Market Basics Table of Contents ... 1 Chapter 1 Introduction ... 1 Physical Fundamentals Financial Markets and T rading ... 2 ... 3 Market Manipulation 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 ransportation ... 21 Natural Gas Processing and T Natural Gas Storage ... 28 Natural Gas Markets and T rading ... 32 Chapter 3 Wholesale Electricity Markets 35 ... Electric Power Industry ... 36 Electricity Demand ... 41 Electricity Supply and Delivery ... 47 Wholesale Electricity Markets and T ... 56 rading RTO Markets and Features 59 ... Regions ... 66 Southeast Wholesale Market Region ... 66 W estern Wholesale Market Regions ... 68 CAISO ... 72 ISO-NE ... 77 ... 82 MISO NYISO ... 87 PJM ... 93 98 ... SPP | Energy Primer i

6 Chapter 4 U.S. Crude Oil and Petroleum Products Markets ... 103 Petroleum ... 104 ... U.S. Crude Oil Supply 105 Petroleum Reserves ... 106 Crude 107 ... Oil Refining ransportation 109 ... Crude Oil and Petroleum Products T 110 Crude Oil and Petroleum Products Demand ... rading Crude Oil and Petroleum Products Markets and T ... 111 Chapter 5 Financial Markets and Trading 113 ... 113 ... Financial Markets and Mechanisms 119 Physical Products ... Financial Products 120 ... T 121 ... rading and Transacting ... Capital Markets 123 127 ... Chapter 6 Market Manipulation 128 ... rading Techniques and Cross-Product Manipulations Manipulative T 129 Information-Based Manipulations ... ... Withholding 119 130 Representative Matters ... The Federal Energy Regulatory Commission retains rights to all photographic images included in the Energy Primer. | C egulatory r nergy ommission ederal F e Energy Primer ii

7 ntroduction 1. i Natural gas, electricity, and oil are forms of energy that are of particular interest to the Federal Energy Regulatory Commis - sion pursuant to its authority under the Natural Gas Act, the Federal Power Act, and the Interstate Commerce Act. This primer for explores the workings of the wholesale markets markets. these forms of energy, as well as energy-related financial energy. Natural gas is the second largest primary source of energy physical the from derived products financial of ing structures consumed in the United States, exceeded only by petroleum. These fi nancial markets and also include market - A primary energy source is an energy source that can be con institutions, market participants, products and trading, and sumed directly or converted into something else, like electric - - have their own drivers of supply and demand. In general, phys and ity. Roughly a third of the natural gas consumed in the United financial markets can be distinguished ical the prod - by ucts and by the intentions of the market participants involved. States goes into power plants for the production of electricity. Physical products are those whose contracts involve the - Electricity, a secondary energy source, results from the con physical delivery of the energy. Physical market participants version of primary fuels such as fossil fuels, uranium, wind, or are those who are in the market to make or take delivery of of electrons used to power into solar modern life. a flow the commodity. Financial products usually do not involve the delivery of natural gas, electricity, or oil; instead, they involve Crude oil and petroleum products are of interest to the Com- the exchange of money. mission because it regulates the transport of oil by pipelines in interstate commerce. can Physical markets be by: further differentiated hubs Location: regions, • zones or nodes, financial and physical both involve markets nergy elements. E daily, hourly, frames: monthly, quarterly or yearly Time • The physical markets contain the natural resources, infrastruc - natural gas molecules or electrons, Types • of products: ture, institutions and market participants involved in produc - pipeline or transmission capacity and storage ing energy and delivering it to consumers. They also include Nature end to sales most involve • sales retail sales: of use or the physical commodity - e.g., the trading of and payment f customers; wholesale sales involve everything else - markets and buying the include sell financial The gas. natural | Energy Primer 1

8 their energy needs at certain times; this might include turning Physical Fundamentals off air to order in day a of part ottest h the during nditioning co help reduce electric load. - Much of the wholesale natural gas and electric power indus - elec most Unlike : Necessity and gas natural products, other try in the United States trades competitively; some markets tric service are necessities today, and a lack of service can are established through administrative processes based on mean customers without heat, the ability to cook or refriger - the cost of providing service. In competitive markets, prices ate food or the ability to run their businesses. Blackouts and are largely driven by the economic concepts of supply and service other disruptions create operating - haz and problems demand. Underlying the supply and demand for energy are ards as well. Consumers cannot postpone the purchase of physical fundamentals - the physical realities of how markets electricity or natural gas. They may be able to turn down their produce and deliver energy to consumers and how they form thermostats, but cannot eliminate consumption altogether prices. These physical fundamentals will be covered in Chap - for an extended period of time. ter 2 (Wholesale Natural Gas Markets), Chapter 3 (Wholesale Electricity Markets), and Chapter 4 (U.S. Crude Oil and Petro- Because consumers have limited ability to reduce demand, leum Products Markets). supply must match demand instantaneously, in all locations. gas and electricity markets differ from oth - Wholesale natural For natural gas, this means production, pipelines and storage er competitive markets, however, in critical ways. While this be sized to and demand, need meet to the greatest potential primer focuses on wholesale markets, demand is ultimately deliveries need to move up and down to match changes in determined at the retail level. Retail use is relatively inelastic consumption. Natural gas has underground and above-ground in the short-term, although this may be less so with some larg- storage options and linepack, which involves raising the pres- er customers. Retail use of natural gas or electricity exhibits sure in a pipeline to pack more molecules into the same space. unique characteristics: some averaging 25 flows gas Natural through a velocities at eline pip the the configuration of re - depending and mph, pipeline on have : Limited customer storage options consumers Retail lated facilities, so new supply can take hours or days to reach few options for storing natural gas and electricity. For natural its destination. That increases the value of market-area stor- gas, large consumers and entities that sell to retail consum - age, which vastly reduces the distance and time needed for ers may be able to store gas, but smaller consumers do not gas to reach consumers. have this option. For electricity, smaller consumers may have batteries, but nothing adequate to ensure refrigeration, for For electricity, storage is more limited, although technologies example. Without storage, consumers cannot buy when pric- and flywheels are being such developed. Hydro - as batteries es are low and use their stored product when prices rise. This electric pumped storage is available in a few locations; this limits consumers’ response to changes in prices. involves pumping water to high reservoirs during times of slack water the letting then demand, - down flow electricity Substitutes consumers have few substitutes for natu - tail Re : hill through electricity-generating turbines when demand for ral gas or electricity, certainly in the short-term. If natural gas power rises. Generating plants, transmission and distribution or electricity prices go up, consumers cannot quickly switch to must and s substation other lines, meet be sized to equipment Longer product. different a switch able be may they term, to the maximum amount needed by consumers at any time, in all to gas from electricity for heating, or they may be able to in - locations. For all practical purposes, electricity use is contem - sulate or install new windows or take other steps to reduce poraneous with electricity generation; the power to run a light their consumption of energy. In addition, demand-response bulb is produced at the moment of illumination. to can would who those reduce benefits provide programs | C r nergy e egulatory ederal F ommission Energy Primer 2

9 markets began as ways for farmers to sell their products, or Financial Markets and Trading even a portion of their production before it was harvested, providing them with capital to continue operations. The energy industries are capital intensive, requiring access Commodity markets evolved to provide other tools for farm- trading support daily to and to markets financial operations, ers (and other commodity producers) to manage their risk, to financial markets requires Access programs. investment price. in notably changes financial These the risk of adverse maintaining an investment grade credit rating to support ac- products were derived from the physical products and are tivities ranging from daily transactions to long-term develop- known as derivatives. Since their inception, trading in physical ment of infrastructure. commodities and derivatives has attracted others to the mar - Financial markets are where companies and individuals go if as from ket, such changes speculators hoping to make a profit they need to raise or invest money. They are important to en - in price. ergy markets in two key ways. First, they provide access to the The market for natural gas and electricity derivatives has capital needed for operations. Second, some natural gas- or grown enormously within the past decade, as competitive electricity-related products may trade in commodity markets natural gas and electricity markets matured and investors derivative products (see below), in financial markets. or, as came to see energy commodities as investments. This trading Natural gas and electricity are traded like commodities, just and is - dis affects the phy sical markets in a number of ways, like metals, corn, wheat or oil. They may not be visible, but cussed in Chapter 5, Financial Markets and Trading. off, and measure them. Commodity you can turn them on and | Energy Primer 3

10 Additional Information Market Manipulation Where there are markets, there will be those who attempt to This primer is written to be used either as a traditional text the markets for their own benefit. These practices – read front to back – or as a reference guide. Consequently, manipulate ability references and sections different undermine the market’s to operate efficiently, reduce material some in is repeated in and dis - the confidence participants’ market other are provided to other parts of the primer where a concept is markets - tort market outcomes, including prices. Some of these prac addressed in greater detail. tices are discussed in Chapter 6, Market Manipulation. 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 oversight market the find here: pages electronically, you can http://www.ferc.gov/market-oversight/market-oversight.asp Google search also provides a quick path to information on to (e.g., subjects general more FERC or specific FERC orders regulation of natural gas pipelines). | C egulatory r nergy ommission ederal F e Energy Primer 4

11 holEsalE n atural g as m arkEts 2. W y Natural gas markets have a sig nificant effect on the econom electric and on the individuals who rely on the fuel for genera - tion, 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. - While natural gas is typically a gas, it can be cooled to a liquid Under the Natural Gas Act (NGA), the Federal Energy Regu and transported in trucks or ships. In this form, it is referred to latory Commission (FERC) has jurisdiction over the transpor- tation and sale of natural gas and the companies engaged in or gas, natural liquefied as LNG. 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. gas in a which physical natural fi is also is There nancial market financial product derived from physical bought and sold as a natural gas. Natural gas markets are also regional, with prices for natural gas varying with the demand characteristics of the to supply basins, pipe - access region’s the market, different lines and storage facilities. Natural Gas Natural gas is primarily methane, which is made of one car- the (CH4), and is among four and atom bon hydrogen atoms materials known as hydrocarbons. Natural gas is colorless and Natural Gas Industry odorless in its natural condition. It is also highly combustible, energy and fewer emissions deal of great a off giving than As noted, the markets of the natural gas industry are both fuels such as coal and oil. Natural gas occurs in geological physical physical the on focuses chapter This financial. and with phase associated gas formations in different ways: as a that noted be should it but markets, gas natural financial - mar - crude oil, dissolved in the crude oil, or as a gas phase not as impacts gas can have significant kets on the physical natural with or sociated rich is gas Natural oil. crude significant any market. significant wet if it e.g., – (NGL) liquids gas natural contains For this discussion, the natural gas industry has three seg- ethane, propane and pentane – mixed in with the methane. In ex includes which segment, supply the is ments. first The - contrast, natural gas is lean or dry if it does not contain these ploration and development of natural gas resources and re- liquids. Processors hydrocarbons liquefiable water, remove serves, and production, which includes drilling, extraction and and other impurities from the natural gas stream to make the gas gathering. The second segment is the midstream sector, natural gas suitable for sale. Natural gas liquids may be pro - in which small-diameter gathering pipeline systems transport cessed out and sold separately. | Energy Primer 5

12 prices for natural gas at various locations. Prices tend to be the gas from the wellhead to natural gas processing facilities, lowest in areas with low-cost production, ample infrastructure where impurities and other hydrocarbons are removed from and limited the gas to create pipeline-quality dry natural gas. The third demand example for yoming, W in Hub Opal the – – and highest where production or transportation is limited - segment is transportation, which includes intrastate and inter and demand is high – Algonquin Citygate, in Massachusetts, state pipeline systems that move natural gas through large- - diameter pipelines to storage facilities and a variety of con for example. Transportation cost from supply to demand ar- the in factor a also is eas sumers, including power plants, industrial facilities and local differentials. price regional distribution companies (LDCs), which deliver the natural gas The natural gas industry in the United States is undergoing a to retail consumers. period of transition. Within the last decade, various factors have shifted the dynamics of supply and demand. These in - not clude, but are limited to, the following: 1. Development of technology, like hydraulic fracturing and access horizontal drilling, enables producers to unconven - tional 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 - Each component of the supply chain is critical in serving cus and investment markets. There are two financial distinct quantity of reserves and tomers. production can affect The for markets gas: natural (1) physical a cash market, which market participants’ expectations about current and future is a daily market where natural gas is bought and sold for of availability the Similarly, prices. supply, can s thu and affect - immediate delivery; and (2) a forward market, where nat pipeline and storage capacity determines which supply basins ural gas is bought and sold under contract for one month are used and the amount of gas that can be transported from prices natural financial The future. in more or gas are the producers to consumers. All of these factors affect the supply often derived from the physical natural gas prices. the supply-demand chain, but they also affect balance, both nationally and regionally. Natural gas demand for power generation is rising and 3. A natural gas hub can occur at the interconnection of two is the in significantly to expected increase years. coming or more pipelines where natural gas is bought and sold. The environ the reflects gas natural for demand plant Power - the hub benchmark used to reflect as U.S. natural gas market mental benefits of the fuel, the operating flexibility of in Lou isiana. a at other whole is the locations Henry Hub Prices - pric natural gas-fired generators, and lower natural gas the not differ - uently freq are as th e actual shown price, but as pollution emit plants power gas-fired Natural es. less air ential, or basis, Henry Hub. to than generators using coal or oil. These plants are also be can site, to easier relatively built and sizes of range a in and differences in result demand different supply in Regional | C r nergy e egulatory ederal F ommission Energy Primer 6

13 can decrease output more flexibly than or large ing – or dropping – within the course of a day, sometimes increase unexpectedly. This unpredictability challenges suppliers and baseload generators, such as nuclear or coal. This ability to change output quickly aids electric system operators in pipelines, especially when pipelines are full. matching generation to customer loads, and enables op- t rapid change s in output from wind and erators to offse Economic Activity and Growth other intermittent generators. Economic growth can increase the amount of natural gas used 4. Pipeline expansions linking the new supply regions to by industry, power plants and commercial entities as consum - markets are changing the relationships between prices ers want more of their products and services. During a reces- in various regions. New interstate pipelines have enabled sion, gas use usually declines. On the other hand, economic regions such as the Northeast and Mid-Atlantic to access growth may raise personal incomes and consumption of elec- new supply sources, expanded the amount of natural tric-powered consumer goods. from and traditional flow can that gas supply sources, Structural can also economy the in changes affect natural gas This enhanced the amount that - re has can overall. flow demand. Declining manufacturing and growing service sec- duced prices and tempered extreme price movements tors result in changes in natural gas use, as does increased during periods of peak demand. global competition. New markets for products and services - may require additional natural gas; movement of manufactur ing overseas may reduce it. Natural Gas Demand Daily and weekly economic activity creates cyclical demand patterns. During the work day, demand rises as people get up Natural gas is already the fuel of choice for many sectors of and go to work or school. Similarly, it declines as they go to the U.S. economy and, in 2014 it met about 27 percent of U.S. sleep. On the weekend, demand tends to vary less over the primary energy needs. Natural gas demand, however, can course of the day. substantially. fluctuate - Over the long term, natural gas use is driven by overall eco Prices of Natural Gas and Coal nomic and population growth, environmental policy, energy and prices for natural gas tech efficiency, nological chang es Just as a home-owner may decide to invest in a furnace and and substitute energy sources such as oil, coal and electric- associated piping to use natural gas for heat, so, too, a power ity. In the short-term, demand stems from weather, economic producer may decide to make long-term investments in natu - activity, and competition from other fuel sources such as coal gas-fired generators. ral These decisions requiring long-term and oil. capital investments are cheapest and easiest to make at the time a home or power plant is built, and are more complicated Weather to change later. Thus, over the long term, demand for natu - costs expected alternative the of ral gas can be affected by factor natu - is the most significant affecting Weather seasonal gas energy sources: the cost of an a natural furnace versus ral gas demand. Natural gas demand can also swing consider- plant l-fired coa versus electric one; the cost of a generating ably within a given day, especially during periods of extreme one fueled by natural gas. temperatures. Short-term changes in weather, such as heat In the short-term, the opportunity for fuel switching has been - waves and winter storms, can send demand and prices soar | Energy Primer 7

14 in generation. Electric grid operators have a significant power Environmental Concerns and choice as to which power plant to dispatch to meet increased Energy Efficiency electric demand. Dispatch is often based on the marginal cost each plant in the generation of fleet. g eneration at available - Natural gas has relatively fewer environmental problems com Plants with lower marginal costs, such as nuclear, typically pared with other fossil fuels, and, consequently, it is increas - dispatch before plants with higher marginal costs, such as ingly used for power generation. In addition to helping urban natural gas. As natural gas prices drop relative to coal prices, areas meet air quality goals, natural gas generation has not ex- n get sooner than natural dispatched ca generation d gas-fire perienced as much negative public sentiment as have nuclear demand from the coal-fired generation, increasin g natural gas and coal-fired generators, making it feasible to site gas-fired power sector. generators closer to load centers. Growth in wind and other coupled when intermittent generation technologies benefit with natural gas generation, which is able to ramp up and Demographics and Social Trends down quickly to complement variable output. Long-term affected by shifting demo - demand can also be profile The natural gas emissions some has also encouraged graphics and social trends. Population growth in warmer cli - urban mass transit bus systems, West Coast port operations mates and declines in the older industrial areas of the North other gasoline from gas natural to shift to fleets vehicle and So has the have toward larger affected natural gas trend use. or diesel fuel. houses. Customer Sectors and Demand In 2007, natural gas used for electric generation overtook gas- for-industrial load to become the largest customer class for natural gas. In 2014, according to the EIA, power generation - used 8.2 Tcf of the 24.6 Tcf of natural gas delivered to consum ers. Industrial, residential, and commercial consumers used 7.8 Tcf, 5.1 Tcf, and 3.5 Tcf, respectively. sector overall de - cu Each contrib utes differently to stomer mand, 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 coin - cide with the winter gas-demand peak, but in fact its growing use of natural gas to produce electricity for air conditioning Today, most households have a proliferation of appliances and has created robust summer demand, which competes with devices that consume electricity, and continue to add more as traditionally that supply would flow into underground gas efficient. they As the trend in genera - become more energy storage for later use in the winter. Industrial demand stays tion of electricity is for a greater share to be fueled by natural relatively constant year-round. gas, natural gas demand can increase from rises in electricity demand. | C egulatory r nergy e ederal F ommission Energy Primer 8

15 constrained during peak times and because the capacity is not In the short term, residential and commercial natural gas use - tends to be inelastic – consumers use what they need regard fully used throughout the year. less of the price. Power plant demand, on the other hand, is more price-responsive as natural gas competes with other Power Generation - fuels, especially coal, in the production of electricity. Price in elasticity implies that a potential for price spikes exists during Generation demand can generators gas-fired time; any at soar periods of supply constraint. 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. Genera - the by influenced be also can demand tion for prices relative natural gas and other fuels, especially coal. Since late 2008, gas-fire dispatched been have generally generators d natural 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 ma- terial paints, for fertilizer, plastics, antifreeze, dyes, - photo film, medicines and Industrial graphic explosives. 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 residen- tial sector for home furnaces, water heaters, clothes dryers fairly remained has decade stoves past and the as over flat Consequently, the mix of customers in a region can affect appliances have become more energy efficient. and homes system operations and costs. Pipelines and other equipment Much of the year-to-year demand variation in this sector can for need to be sized to peak demand. Demand that account be attributed to the weather during a particular year. A year stays fairly constant presents fewer operational challenges with a long, cold winter will see higher gas demand than a year enjoys lower and prices. will Highly demand variable usually with a mild winter, especially in cold-winter regions where de - result in pipelines and equipment being used at less than full mand soars during winter months as consumers turn on their capacity for much of the year, and prices for service may be furnaces. Slightly more than half of the homes in the United more expensive, both because the pipelines may become States use natural gas as their main heating fuel. | Energy Primer 9

16 Commercial Like the residential sector, commercial consumption experi - ences year-to-year variation based on weather. Commercial consumers include hotels, restaurants, wholesale and retail stores and government agencies, which use natural gas pri - - marily for heat. Consequently, its demand varies over the sea sons, weeks and days. Natural Gas Supply Natural Gas Resources, Reserves and Production - The amount of natural gas in the ground is estimated by a va Resources is the largest category, which describes the total riety of techniques, taking into account the technology avail- potential of natural gas supply. Proved reserves consider the able to extract the gas. Estimating the technically recoverable feasibility and economics of extracting the natural gas. Last - oil and natural gas resource base in the United States is an ly, production describes the amount of natural gas removed evolving proces s. Analysts use different methods and systems from the ground. to make natural gas estimates. Natural gas supplies are char- Natural gas is located underneath the surface of the earth. acterized as res ources, proved and production (See reserves - for rock of type the by characterized is gas Natural or basin Quick Facts box). mation in which it lies. Conventional natural gas is found in porous rock formations, and in the United States is the tradi- tional source of natural gas. Quick Facts: Resources and Proved Reserves Unconventional natural gas, on the other hand, is found in • Resources - T otal natural gas estimated to exist in - shale, coal seams and tight, low-permeability rock forma a particular geological area. of size estimated The National the 2007, In tions. defined Petroleum Council (NPC) resources is different from the amount of natural unconventional gas as “natural gas that cannot be produced gas that can or will be produced from that area. rates or in economic flow volumes of natural gas at economic unless the well is stimulated by a large hydraulic fracture treat- Proved reserves • - Estimated amount of natural gas wellbore horizontal a by or using multilateral wellbores ment, that, based on analysis of geologic and engineer- or some other technique to expose more of the reservoir to ing data gathered though drilling and testing, can the wellbore.” be reasonably projected to be recoverable under existing economic and operating conditions. Since In the past few years, improvements in drilling technology economic and operating conditions change con- have enabled producers to access unconventional supplies, stantly, the estimates for proven reserves also significant notably shale, yielding increases in production changes often. - and raising the estimate of proved reserves. Estimates of re | C egulatory r nergy ommission ederal F e Energy Primer 10

17 between rig count and production. The oil and gas rig count sources in 2014 amounted to approximately 2,853 Tcf (which included reserves). peaked at 4,530 on Dec. 28, 1981. Since then, rig count has - decreased by over 80 percent while rig productivity has in This domestic growth in resources and reserves has trans - Inc. Hughes Baker to according substantially, creased Within lated into greater natural gas production, which has grown l tota the in used rigs, drilling horizontal of use the count, rig more than 35 percent since 2005, to more than 70 billion cubic the production of natural gas and oil in shale formations, has feet per day (Bcfd) in 2014. Most of the growth came from been growing for years, while the traditional vertical rig count shale gas, which now accounts for 50 percent of natural gas has steadily declined. resources. adoption The has ling significantly dril horizontal of increased Gas Exploration and Development Process production per rig, making comparison of rig counts over time problematic more considerably are rigs al horizont because 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 buried and pressurized. The was remains of that organic ma - terial 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 Source: FERC staff to 9,000 feet; organic materials at greater depths and higher temperatures result in natural gas. Schematic Geology of Natural Gas Resources Worldwide, the United States accounts for one-tenth of glob - al 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 num ber of rotary drilling rigs actually drilling for oil and gas. These measures are compiled by several companies active in drill- operations. Historically, rig counts ing were used as a rough predictor of production. in improvements However, future drilling technology and practices have caused a decoupling Source: EIA | Energy Primer 11

18 Gas Production in Conventional Fields, Lower 48 States Source: EIA Mountains to the Gulf of Mexico to Appalachia. The largest Natural gas basins are frequently referred to as conventional nventional basins or plays. These basins differ in the unco or conventional fields reside in T exas, W yoming, Oklahoma, New federal geology of the basin and the depth at which gas can be found. the In Mexico. of Gulf the and of area e offshor Mexico The percent 24 represented production gas atural sch ematic illustrates differing geologic formations in shore off 2000, n of total U.S. production; by 2013 that amount had fallen to less which natural gas can be found. than 5 percent. Conventional Natural Gas natural gas wells are drilled Federal in the ocean floor offshore Natural gas historically has been produced from what is tradi - the of coast the off waters in - jurisdic are States that United tionally known as conventional natural gas resources, which - tional to the federal government. Most states have jurisdic provided most of the country’s supply needs for more than tion over natural resources within three nautical miles of their a century. Conventional gas is found in geological basins or coastlines; Florida and Texas claim nine nautical miles of juris- reservoirs made of porous and permeable rocks, holding sig - diction. in nificant amounts of natural gas in rocks. the the spaces Roughly 4,000 oil and gas platforms are producing in federal found Conventional re sources have been both on land and off - waters at water depths approaching 7,500 feet (at total well arc from the Rocky shore (see map) , with the majo r fields in an depths of 25,000-30,000 feet) and at distances as far as 200 | egulatory r nergy e ommission ederal F C Energy Primer 12

19 Source: EIA from sho re, the EIA miles reports. Most of these offshore wells are in the Gulf of Mexico. As on close- Offshore production has been going for decades. in, shallow-water wells became less economic to produce, companies looked to reserves at greater water depth. Tech - nological improvements contributed to continuing produc - offshore wells. tion from deep Unconventional Natural Gas In recent years, innovations in exploration and drilling tech - Source: EIA nology have led to rapid growth in the production of uncon - ventional natural gas. This term refers to three major types The presence of natural gas in these unconventional plays has of formations where gas is not found in distinct basins, but been common knowledge for decades, but it was not until the is trapped in shale, tight sands or coal seam formations over early 1990s, when after years of experimenting in the Barnett large areas. | Energy Primer 13

20 Coalbed Methane Fields, Lower 48 States Source: EIA There are about 20 tight sands basins in the United States (see Shale in Texas, George Mitchell and Mitchell Energy Co. devel- map); as of 2012, annual production was about 5 Tcf, or about oped a new drilling technique that made production in these one-fifth types of formations economically feasible. The new technol - production. domestic U.S. of wells, which ogy allow a included horizontal and directional Coalbed methane (CBM) is natural gas trapped in coal seams. - producer to penetrate diverse targets and increase the pro are coalbeds Fractures, filled or cleats, that permeate usually ductivity of a well. Directional wells allow the producer to tap with water; the deeper the coalbed, the less water is present. The these resources through multiple bores. horizontal wells To release the gas from the coal, pressure in the fractures is move the through horizontally have then but bore, vertical a created by removing water from the coalbed. rock to access more supply. These new drilling technologies greatly improved the likelihood of a successful well and the The coalbed methane resource of the United States is estimat - productivity of that well. ed to be more than 700 Tcf, but less than 100 Tcf of that may be economically recoverable, according to the U.S. Geological As of 2014, production from unconventional reserves supplied Survey. Most CBM production in the United States is concen - nearly two-thirds of U.S. gas needs. the - trated in signifi Rocky Mountain area, although there is Tight sands gas is natural gas contained in sandstone, siltstone cant activity in the Midcontinent and the Appalachian area. and carbonate reservoirs of such low permeability that it will nd in fine-grained sedimentary rock with low Shale gas is fou T o extract tight sands not natu rally flow when a well is drilled. permeability and porosity, including mudstone, clay stone and gas, the rock has to be fractured to stimulate production. | egulatory r nergy e ederal F ommission C Energy Primer 14

21 Source: EIA for ses - for geological finding In proces e past decade the th mations 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 a in resulted have and gas, shale producing and finding of cost - account gas shale 2014, In production. in increase significant ed for about 45 percent of total gas production, with expecta - of future. the tions in increases significant As of 2014, the six major shale plays in the United States are Barnett, and Ford, Eagle Haynesville, oodford, W Fayetteville, Marcellus (see map on next page). Other shale formations are Source: Geology.com seeing heavy exploration activity and are expected to become what is commonly known as shale. These rock conditions re- major contributors of natural gas supply in the near future. quire a special technique known as hydraulic fracturing (frack- The shale plays are widely distributed through the country, ing) to release the natural gas. This technique involves frac- which has the added advantage of putting production closer radial using shaft al horizont the in of series a turing the rock to demand centers, thus reducing transportation bottlenecks explosions and water pressure (see graphic). | 15 Energy Primer

22 Shale gas well productivity has improved considerably over and costs. the past 10 years, with technological advances in drilling and Many shale reservoirs contain natural gas liquids, which can fracking technology reducing exploration, drilling, and pro- be sold separately, and which augment the economics of pro - ducing costs. Rising well productivity and falling costs have ducing natural gas. resulted in larger amounts of shale gas production at lower natural gas prices. The Shale Revolution The presence of NGL in many shale gas plays adds to shale linked closely more are prices NGL profitability. oil to gas well The estimated resources, proven reserves and production of prices than natural gas prices and natural gas wells with high - shale gas have risen rapidly since 2005, and shale is transform therefore content - pro wells than profitable more liquids are ing gas production in the United States. In 2013, according to ducing natural gas alone. A typical barrel of NGL might con - EIA, shale gas made up 40 percent of gross production of nat- tain 40-45 percent ethane, 25-30 percent propane, 5-10 per- ural gas, and has become the dominant source of domestically cent butane and 10-15 percent natural gasoline. This can make produced gas. By comparison, coalbed methane accounted shale gas wells less sensitive to natural gas prices than wells for 5 percent of production, while 18 percent of the natural producing just natural gas. gas came from oil wells and 38 percent was produced from natural gas wells. - The Marcellus Shale formation in Appalachia is of particu of e becaus note lar resource and size n, locatio potential, its New shale plays have increased dry shale gas production from according to the Potential Gas Committee at the Colorado 1 Tcf in 2006 to over 12 Tcf in 2014. Wet shale gas reserves, School of Mines. Marcellus Shale has estimated gas resources natural about for account liquids as g those and/or oil in rich 20 reaching 549 Tcf, and it extends from West Virginia to New - percent of the overall United States natural gas reserves. Ac York, near the high population centers of the Northeast and cording to the EIA, shale gas will account for about 53 percent Mid-Atlantic. Although Marcellus Shale has been producing of United States natural gas production in 2040. since significant amounts of gas only 2008, production has Shale Gas Production by Region high prolific with been initial well pressures and high produc - tion rates. Growing gas production in Marcellus has already made an U.S. gas transporta tion. impact on more gas has flowed As out of Marcellus, less gas has been needed from the Rock- ies or the Gulf Coast to serve the eastern United States. This new production has contributed to a reduction in natural gas differentials and the long-standing price prices 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 chal - lenge to continued shale development. One issue involves the amount of water used for hydraulic fracturing and the disposal – chemicals and sand are combined with of the effluent used Source: Derived from EIA data water to create a fracturing solution, which is then pumped | C egulatory r nergy ommission ederal F e Energy Primer 16

23 into deep formations. Some companies recycle the returned Imports and Exports water, which allows them to reuse such water. Concerns have also been raised regarding the potential - risks and health haz Net natural gas imports play an important role in regional U.S. ards associated with wastewater (especially when stored at markets, accounting for about 1,181 Bcf, or 4 percent, of the ground level in holding ponds) seeping into drinking water. natural gas used in the United States in 2012. The natural gas - pipeline systems of the United States and Canada are integrat - ed, and about 98 percent of imports came from Canada, ac FERC Jurisdiction liquefied EIA, the to cording 2 percent was imported as while natural gas (LNG). Section 1(b) of the Natural Gas Act (NGA) exempts production and gathering facilities from FERC jurisdiction. Moreover, the gas flows - into natural Imported the United States via pipe Wellhead Decontrol Act of 1989, Pub. L. No. 101-60 (1989); 15 lines at numerous points along the U.S. border with Canada. U.S.C. § 3431(b)(1)(A), completely removed federal controls Imports from Canada have been of strategic importance in the - on new natural gas, except sales for resale of domestic natu Northeast and the West, which were traditionally far from the ral gas Order In affiliates. their or Cs LD pipelines, interstate by domestic imports However, centers. major production from No. 636, FERC required interstate pipelines to separate, or - Canada have been declining as U.S. shale production has in unbundle, their sales of gas from their transportation service, creased. Net U.S. gas imports fell from a high of 3,785 Bcf in - and to provide comparable transportation service to all ship 2007 to 1,181 Bcf in 2014. EIA estimates that imports will con - pers whether they purchase natural gas from the pipeline or tinue to decrease as shale-gas production increases. another gas seller. 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 | Energy Primer 17

24 The LNG Supply Chain Liquefied Natural Gas Natural gas is sent to liquefaction facilities for conversion to gas (LNG) is natural gas cooled to minus 260 Liquefied natural LNG. These facilities are major industrial complexes, typically degrees Fahrenheit to liquefy it, which reduces its volume by costing $2 billion, with some costing as much as $50 billion. - 600 times. LNG may be transported in ships and trucks to loca tions not connected by a pipeline network. specialized by transported typically is LNG the liquefied, Once ships with cryogenic, or insulated, tanks. FERC Jurisdiction import is it terminal, (regasification) un an reaches LNG - When loaded and stored as a liquid until ready for sendout. To send ity NGA the under authorize author exclusive has FERC The to regasification return to LNG the the gas, out warms terminal the siting of facilities for imports or exports of LNG. This au - - it to a gaseous state and then sends it into the pipeline trans applicant’s the on ioned condit - is ever, how thorization, satis portation network for delivery to consumers. Currently, over faction of other statutory requirements not administered by 95 Bcfd of than regasification capacity exists globally, more FERC for various aspects of the project. In addition, the De- 2.5 times the amount of liquefaction capacity. Excess regasifi - partment of Energy has authority over permits to import and cation capacity provides greater flexibility to LNG suppliers, export. 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 produc - tion and liquefaction and the distance over which the LNG is shipped. Liquefaction and shipping form the largest portion of th e costs. Regasification co ntributes the least cost of any The component in the LNG supply chain. cost of a regasifi - cation facility varies considerably; however, the majority of these costs arise from the development of the port facilities tanks. A 700-MMcfd regasification terminal the storage and may cost in the range of $500 million to $800 million. Source: BP The various components of the LNG process are broken out on the following page. | C egulatory r nergy ommission ederal F e Energy Primer 18

25 LNG in the United States The United States is second Japan in LNG regasification to capacity. As of 2014, there were 11 LNG receiving or regasifi - cation terminals in the continental United States, with ap - proximately 19 Bcfd of import capacity and 100 Bcf of storage capacity. All of these facilities are on the Gulf or East coasts, - re or just import offshore. In addition, the United States can LNG into New England gasified from the Canaport LNG termi - nal in New Brunswick, Canada, and into Southern California Baja California. from the Costa Azul LNG terminal in Mexico’s Source: CEE based on industry and government reports Source: FERC staff | Energy Primer 19

26 Between 2003 and 2008, the United States met 1-3 percent of under short-term contracts or as spot cargoes. LNG prices in its natural gas demand through LNG imports, according to the the United States generally link to the prevailing price at the imports peaked at about 100 EIA. Bcf/month in the sum - LNG closest trading point to the import terminal. During 2011-14, mer of 2007. Growth in relatively low-cost U.S. shale gas pro- the growth in shale gas production led to proposals to export LNG of As LNG. produced duction has trimmed U.S. imports, affecting Gulf of Coast volumes significant domestically - Janu terminals the most. Today, most LNG enters the United States ary 2015, several LNG export facilities have been approved, under long-term contracts (about half of the total) coming but none have yet begun operations. Since 1969, small quan - shipped from Alaska to Pacific through the Everett (Boston) and Elba Island (Georgia) LNG Rim been tities of LNG have countries. terminals. The remainder of the LNG enters the United States Source: FERC staff | C egulatory r nergy ommission ederal F e Energy Primer 20

27 of wellhead, or raw, composition The natural gas differs by Natural Gas Processing and region. depending Consequently, processing the on differ will Transportation quality of the natural gas. Natural gas may be dissolved in oil underground but separated out from the oil as it comes to - Most domestic natural gas production in the United States oc the surface due to reduced pressure. In these instances, the curs in regions well away from major population centers. To oil and gas are sent to separate processing facilities. Where it - get gas from the wellhead to consumers requires a vast net does not separate naturally, processing is required. work 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. that this network be markets Efficient robust and al - require low consumers access to gas from more than one production center. Supply diversity tends to improve reliability and mod- erate 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 seg- Source: EIA - ment involves gathering the gas from the wellhead, process ing 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 indi Once a well is completed and production starts, the natural - vidual components. The liquids are used by the petrochemi gas moves into gathering pipelines, typically small-diameter refineries There cal consumers. industrial other and industry, - lines that move the gas from the wellhead to either a process were about 500 gas processing plants operating in the United ing plant or a larger pipeline. States in 2010. - Processing is required when the natural gas and oil do not sep arate naturally. At the processing plant, wet natural gas is de- hydrated, and additional products and contaminants (such as sulfur and carbon dioxide) are extracted. The hydrocarbon liq - uids, 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 which by fractionation, 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. | 21 Energy Primer

28 Nearly one-sixth of all natural gas transmission pipelines, by FERC Jurisdiction mileage, are located in Texas. More than half are located in Kansas, Oklahoma, California, Il - exas, T states: nine Louisiana, The NGA gives the FERC comprehensive regulatory authority linois, Michigan, Mississippi and Pennsylvania. over companies that engage in either the sale of natural gas for resale or its interstate transportation. The Commission Compressor stations, located every 50-100 miles along the regulates market entry through Section 7 of the NGA, 15 U.S.C. pipe, add to or maintain the pressure of the natural gas, pro- by issuing certificates - § of public 717f, convenience neces and pelling it down the pipeline. Natural gas travels through pipe- sity, subject to such conditions as the Commission deems ap - lines at high pressures, from 200 pounds per square inch (psi) transport to propriate, or auth companies gas natural orizing to 1,500 psi. sell natural gas. To this end, the FERC reviews applications for the construction and operation of interstate natural gas The natural gas is compressed by turbines, motors or engines. pipelines. In its application review, the FERC ensures that the Turbines and reciprocating natural gas engines use some of it will comply with Department of applicant has certified that the gas from the line to fuel their operations; electric motors Transportation safety standards. The FERC has no jurisdiction rely on electricity. over pipeline safety or security, but actively works with other - agencies with safety and security responsibilities. The Com - mission regulates market exit through its authority to aban service, 15 U.S.C. § 717f(b). don certificated Natural Gas Infrastructure The United States natural gas market is accommodated Natural Gas Transportation extensive by infrastructure: - Roughly 303,000 miles of wide-diameter, high pres • Interstate pipelines account for 63 percent of the natural gas - sure inter- and intrastate pipelines make up the main pipeline miles in the United States and carry natural gas across line pipeline transportation network, run by more - state boundaries. Intrastate pipelines account for the remain than 210 companies. - ing 37 percent, and have similar operating and market charac More than 1,400 compressor stations maintain pres - • teristics. sure on the natural gas pipeline network. • More than 5,000 receipt points, 11,000 delivery - The interstate network moves dry natural gas from produc points and 1,400 interconnection points implement ing areas to LDCs, large industrial customers, electric power of gas across the the United States. flow plants and natural gas storage facilities. The pipelines, which • dozen provide centers market or hubs three Nearly addition interconnections. range in diameter from 16 inches to as large as 48 inches, Over 400 underground natural gas storage facilities • move gas between major hubs to lateral lines. Laterals, which of the system. increase the flexibility range in diameter from 6 inches to 16 inches, distribute gas to • 49 locations enable natural gas to be imported or retail customers. exported via pipelines. • There are 9 LNG import facilities and 100 LNG peak - The large pipelines are known as mainline transmission pipe - ing facilities (stored gas held for peak demand lines. The pipe used for major pipelines typically consists of periods). sufficient to meet standards set by strong the carbon steel • More than 1,300 local distribution companies deliver American Petroleum Institute. The pipe is coated to reduce natural gas to retail customers. corrosion. Smaller distribution lines, which operate under Source: EIA much lower pressures, may be made of plastic materials, flexibility ease and of provide which replacement. | C r nergy e egulatory ederal F ommission Energy Primer 22

29 Metering stations are placed along the pipelines to measure compressor station data. SCADA also conveys this informa - natural gas as it moves through the system. - flow the of tion to the centralized control station, allowing pipeline engi neers to know what is happening on the system at all times. Movement of natural gas along a pipeline is controlled in part by a series of valves, which can be opened to allow the gas As the product moves closer to the consumption areas, it may section of to move freely or closed to stop gas flow along a be stored in underground facilities. Plentiful storage capacity systems pipe. Large valves may be placed every 5 to 20 miles along the distribution and pipeline and adds flexibility to the pipeline. helps moderate prices by providing an outlet for excess gas during periods of low demand, and readily accessible supply in - Pipeline operators use supervisory control and data acquisi periods of high demand. Some natural gas can also be stored tion (SCADA) systems, to track the natural gas as it travels in the pipelines as linepack, in which more molecules of gas centralized communication their through systems. SCADA is a are held in a segment of pipeline under greater-than-normal system that collects, assimilates and manages the meter and pressure. Natural Gas Transportation System Source: Derived from Velocity Suite, ABB | Energy Primer 23

30 Source: Sabine Pipeline, LLC Hubs in Hub acceptance Henry widespread the 1990 that gained and is generally used as the reference price for natural gas in A key part of the pipeline distribution network is the natural the United States. a specific point where pipeline in - gas hub . T ypically, a hub is Distribution lines typically take natural gas from the large terconnections allow the transfer of gas from one pipeline to transportation pipelines and deliver the gas to retail custom - another. - ers. While some large consumers – industrial and electric gen country, with over There are dozens of natural gas hubs in the directly off - transmis eration, for example – service take may a Henry 20 majo benchmark dominant the is b Hu r The hubs. sion pipeline, most receive their gas through their local gas point in the physical natural gas market because of its strate- utility, or LDC. These companies typically purchase natural gas gic location in the Gulf Coast’s producing area and the number and ship it on behalf of their customers, taking possession of of pipeline connections to the East Coast and Midwest con - the gas from the pipelines at local citygates and delivering it sumption centers. It is located in south central Louisiana, in to customers at their meters. This distribution involves a net - major natural the town of Erath, where more than a dozen - work of smaller pipelines – more than two million miles, ac exchange gas pipelines converge and has gas. The Henry Hub cording to the U.S. Department of Transportation. 12 delivery points and 4 major receipt points. FERC Jurisdiction the Henry sold at and bought be can product physical a as Gas the monthly and daily in country Hub around hubs other or The NGA requires that interstate natural gas pipelines charge markets. In addition, the New York Mercantile Exchange (Ny - just and reasonable rates for the transportation and sale of mex) established a natural gas futures contract centered at | C egulatory r nergy e ederal F ommission Energy Primer 24

31 release segments rather than their full holdings, provided seg- natural gas. To promote compliance with this mandate, the mentation is operationally feasible on the interstate pipeline’s the to file rate schedules with FERC pipelines NGA gas requires system. and to notify the FERC of any subsequent changes in rates and charges. a tariff revision, the FERC may hold On submission of Interstate pipelines also provide “no-notice service” under a hearing to determine whether the pipeline has met its bur- their to up delivery receive may shippers firm - which enti firm den to show that the amended rates and charges are just and on a daily basis witho ut tlements penalty. If a shipper firm has reasonable. storage and transportation service, that shipper can schedule in the day-ahead market and yet have the ability and the right Under Sections 4 and 5 of the NGA, 15 U.S.C. §§ 717c and 717d, - sched was what than quantity different a take ically phys to the Commission regulates the rates and other terms of juris- uled without incurring imbalance penalties. No-notice service dictional transportation and sales, ensuring that rates and is particularly valuable during periods of high demand when charges for such services, as well as all rules, regulations, prac- transportation capacity may be completely used. This service tices, and contracts affecting those rates and charges, are just is especially helpful to LDCs that must serve their load without and reasonable and not the product of undue discrimination knowing their exact load level each day. No-notice service is (15 U.S.C. §§ 717c(a) and (b)). transportation firm to premium a at priced generally service. Shippers may temporarily release this service to other parties, Pipeline Services using FERC-approved capacity release guidelines. Customers or shippers may choose among a variety of servic- Interstate Transportation Rates capacity, transportation firm is One pipelines. interstate on es or primary market service, in which an agreement is executed can rates transportation Pipeline be priced on zones or miles, directly between the pipeline and a customer for a year or be a fixed po stage stamp rate. In zonal pricing, the price of or more, relying on primary receipt and delivery points. Shippers transportation varies by the location of the receipt and deliv - firm transportation with generally receive priority to service of zones. ery across a series points, ship for the contracted quantity. Under postage stamp rates, shippers pay the same rate for A second type of transportation service a shipper can contract transportation regardless of how far the gas is moved, similar - for is interruptible transportation service. Interruptible trans to the way a postage stamp costs the same amount regard- under is customers offered schedules or service portation to - less of whether a letter is sent to New York or California. Pipe - contracts on an as-available basis. This service can be inter lines using postage stamp rates include Northwest Pipeline, a on or days of number specified a for notice ort sh rupted Colorado Interstate Gas and Columbia Gas Transmission. hours during times of peak demand or in the event of system With mileage-based rates, shippers pay based on the distance emergencies. In exchange for interruptible service, customers between where the gas enters the pipeline and where it is pay lower prices. the pipeline. e th of out reflect taken to designed is rate The secon dary market for A firm transportation rights enables distance involved in transporting the gas. Gas Transmission shippers to sell their pipeline capacity to a third party through Northwest (GTN) uses mileage-based rates. FERC’s the in offered the Services program. release capacity Other pipelines use hybrid or mixed-rate systems. Northern can primary the by market secondary the in offered be market rate zonal combination a uses example, r fo Gas, Natural for capacity offers market holder of primary service. Released the upstream receipts and a postage stamp rate for market area participants the opportunity to buy and sell from each other deliveries. the capacity primary of Holders pipeline. can from as well as | Energy Primer 25

32 S ource: Bentek Energy LLC demands, different serving to accustomed which are Pipelines Scheduling used is pacity ca their of at much how affect can various times. Pipelines have rigorous schedules that shippers must follow. example, at For Kern River Gas T ransmission has operated Typically, shippers nominate gas in the day-ahead market, and around 93 percent of capacity since 2005, while Algonquin may update their nominations at various points during the day Gas Transmission’s capacity factor is considerably less. Algon - which the natural gas flows. The Pipeline in Capacity Schedul - re River’s, Kern than seasonally - more used is pipeline quin’s ing graphic illustrates a particular schedule. in the the Northeast. flecting demand seasonal Pipeline Usage or Load Factor Park and Loan Service Load factor measures the use of a pipeline network. It is the Park and loan service (PAL) is a way for shippers to balance average capacity used at a given point or segment relative to their takes of gas with their supply, by providing a short-term a measurement of maximum or peak available capacity. Cus - load-balancing service to help shippers meet their load. Using tomers with a 100 percent load factor use their maximum ca - the PAL service, shippers can take less gas than scheduled, pacity every day; one with a 50 percent load factor uses its thus parking their excess supply in the pipeline at times when of capacity only ha lf use customers types erent Diff time. the the demand is lower than anticipated. If demand is higher capacity differently. Historically, pipeline industrial customers - than expected, shippers can adjust their take upward, in ef have exhibited high load factors and residential customers fect borrowing gas from the pipeline. that primarily rely upon seasonal gas to heat homes have had lower load factors. | C egulatory r nergy e ederal F ommission Energy Primer 26

33 include: characteristics PAL displaced gas from the Permian Basin. Permian natural gas, in turn, began moving to the Southern California market. Conse - Park and loan services typically generate low revenue and • regional the price However, moderated. differences quently, among priority level service all lowest the with offered are rapid increase in Marcellus Shale production pushed Rockies pipeline services. on flows caused and east North the from away supplies REX • Rates are based on costs associated with providing the the to decrease sharply, In risk. financial at pipeline putting if the plant costs as such services, services are offered. flows reversing of process the began REX 2014, the of parts on these Market • centers, or hubs, routinely services. offer pipeline to move natural gas from the east to the Midwest. • Charges are usually commensurate with interruptible This development is making more Rockies natural gas avail - service rates. able to Western Markets, and more midcontinent production • Pipelines earn minimal revenue from park and loan. available for the Gulf Coast and Southeast states. Other projects are operating as designed. New pipelines to Pipeline Constraints and Capacity Growth of - net interstate the into gas Shale Barnett flow the increase Pipeline capacity limits the supply that can be delivered to a work have reduced congestion across the Texas-Louisiana a prices. region and is, therefore, specific key factor in regional border. In recent years, the natural gas pipeline network has expand - The Florida Panhandle and Northern California used to be and signifi cantly, removing bottl enecks ed providing access to - some of the most frequently constrained regions of the coun previously unreached supply areas. but try, significant received capacity. pipeline new has each Expansion of Florida Gas Transmission in 2011 added about A considerable amount of new pipeline capacity has been 800 MMcfd, a boost of 33 percent, of gas transmission capac - - added in recent years to the Northeast. As Northeast produc ity to peninsular Florida. The 680-mile, 42-inch-diameter Ruby tion ramped up in 2008 and 2009, annual pipeline capacity ad- Rockies flows now 2011, in operations began which Pipeline, ditions in the region rose to 2.6 Bcfd in 2009 along with the gas from Opal, Wyo., to Malin, Ore. production increases. Pipeline capacity additions moderated in 2010 and 2011 until surging again to reach annual additions Local Distribution - of 2.9 Bcfd in 2012 and 2.6 Bcfd in 2013. Much of this new ca Distribution lines typically take natural gas from the large inter- pacity was targeted at improving access to shale gas. state pipelines and deliver the gas to retail customers. While Building a pipeline project requires careful planning, as the some large consumers – industrial and electric generators, for that costs significant entail typically projects - re be must service an off dir ectly may – example pipeline, interstate take over years covered operations. However, unanticipated of most receive their natural gas through their LDC. LDCs typical - changes in supply and demand patterns can have unexpected ly purchase natural gas and ship it on behalf of their custom - on effects the best-planned projects. For example, one even ers. They take possession of the natural gas from interstate of the largest additions to the natural gas infrastructure came pipelines at local citygates and deliver the natural gas to their - when the 1.8-Bcfd Rockies Express Pipeline (REX) was com customers at the customer’s meter. According to the United pleted in 2009. REX was designed to move natural gas from Hazard of Department States and - Pipeline ransportation’s T - Wyoming to eastern Ohio in order to relieve pipeline con ous Materials Safety Administration, this distribution involves straints that bottled up production and depressed prices in a network of smaller pipelines totaling more than two million the Rockies, while at the same time providing needed supplies miles, as well as smaller scale compressors and meters. into went first - When East. the into pro Rockies service, REX Rockies gas flowing eastward saw rise ducers in prices. The a Some states allow competition in natural gas service at the | Energy Primer 27

34 EIA’s weekly storage report provides a high-level snapshot of local level. In these circumstances, natural gas marketers pur- chase the natural gas and arrange for it to be shipped over the natural gas supply and demand balance. EIA releases its - natu for price The Thursdays. both the interstate pipeline network and the LDC system. on a.m. 10:30 at report storage ral gas futures can change dramatically within seconds of the reported the - signifi If release. report’s withdrawal or injection expectations, from natural for price the market differs cantly Natural Gas Storage gas futures may rise or fall. Although natural gas production rose steadily from 2005 through 2014 because of the increase in shale gas production, Storage Facilities day-to-day production remains relatively steady throughout the year. Demand, however, changes considerably with the The bulk of the storage capacity in the United States is below - seasons. Natural gas storage enables producers and purchas cost and affect characteristics erational g Differin op ground. ers to store gas during periods of relatively low demand – and each used: how is facility low prices – then withdraw the gas during periods of relatively Deliverability rate is the rate at which inventory can be • higher demand and prices. withdrawn. The faster the natural gas can be removed Working gas storage capacity, as tracked by EIA, was more from storage, the more suitable the storage facility is to than 4,100 Bcf in 2014. The amount injected or withdrawn is helping serve rapidly changing demand. and Storage production. - demand between ca the difference systems and adds flexibility to pacity pipeline and distribution • Cycling capability is the ability of the resource to quickly helps moderate prices by providing an outlet for excess gas allow injections and withdrawals, which is useful for bal - during periods of low demand. Storage facilities also provide ancing supply and demand. Salt caverns tend to have high a readily accessible supply in periods of high demand. Some withdrawal and injection rates, enabling them to handle natural gas can also be stored in the pipelines as linepack, in injection cycles as a dozen withdrawal and as many each which more molecules of gas are held in a segment of pipeline year. LNG storage also demonstrates these capabilities. under greater-than-normal pressure. | C egulatory r nergy e ederal F ommission Energy Primer 28

35 Underground Natural Gas Storage Facilities in the Lower 48 States west. These aquifers consist of water-bearing sedimentary Natural gas in an underground storage facility is divided into rock overlaid by an impermeable cap rock. Aquifers are the two general categories, working gas and base gas. Base gas most expensive type of natural gas facility because they do is the volume of natural gas, including native gas, needed as not have the same retention capability as depleted reservoirs. a permanent inventory in a storage reservoir to maintain ad- Therefore, base gas can be well over 50 percent of the total equate reservoir pressure and deliverability rates throughout - gas volume. This makes the facility more sensitive to with the withdrawal season. Working gas is the volume of gas in drawal and injection patterns, so inventory usually turns over the reservoir above the designed level of base gas and that just once a year. can be extracted during the normal operation of the storage facility. Types of Underground Storage Facilities Most of the nation’s gas storage is in depleted reservoirs (for- the fields). These facilities reuse and infrastructure mer oil gas - – wells, gathering systems and pipeline connections – original support the field when it was producing. About ly created to 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 trans formed into gas storage facilities. These are mostly in the Mid - | Energy Primer 29

36 Salt cavern formations exist primarily in the Gulf Coast region. the EIA. Facilities operated by interstate pipelines and many These air- and water-tight caverns are created by removing others are operated on an open-access basis, with much of salt through solution-mining, leaving a cavern that acts as a - the working gas capacity available for lease on a nondiscrimi Little base gas required, which allows vessel. pressurized is natory basis. turn over as man y as a dozen times during the inventory to - The ability to store large quantities of natural gas improves re year, and results in high injection and withdrawal rates. This on influence gas natural liability and usually has a moderating resulting in the growth flexibility attracted new develo pment, prices. Storage inventory augments natural gas supply during of salt cavern storage through 2008. Salt caverns generally the winter, and acts as an additional demand component dur- hold smaller volumes than do depleted-reservoir or aquifer ing the summer injection season. The storage injection season gas storage facilities. typically starts April 1 and continues through Oct. 31, when de- mand for gas heating is lowest. Storage withdrawals generally Natural gas may also be stored in above-ground tanks as LNG. - There is LNG storage at all of the onshore LNG-receiving termi start in November and last throughout the winter. nals, and there are about a hundred standalone LNG storage The ability to use storage to provide for winter peaks creates facilities in the United States, as well. LNG ships can also serve an intrinsic storage value. This is the value from buying dur- as storage, depending on timing and economics. LNG storage - ing cheaper periods of the year for use during higher-cost sea is highly flexible, allowing multiple inventory turns per year sons. Depleted reservoirs or aquifers – with limited ability to with high injection and withdrawal rates. - turn over inventory – support this type of use. Local distribu tion companies or pipelines store their gas in these facilities to Regional Storage ensure adequate supplies for peak seasons, balance load and diversify their resources. storage three into States United the divides EIA The regions: producing, East and West. Just over half of the underground Storage may be priced at cost-based or market-based rates. storage in the United States, 2,200 Bcf, sits in the East near - isms mechan Pricing depleted low-cycling for fields and aqui population centers. Much of this is in aquifers and depleted may including: structure, cost-of-service fers traditional a use has fields. Almost 1,500 Bcf sits in the producing region, which • - charges for firm contract stor physical to rights Capacity not fields depleted only but the greatest concentration also age capacity The rage. sto cavern salt more-flexible is Bcf 600 remaining of Deliverability charges for transportation to and from the • total working gas in the W est, primarily in depleted fields, for storage facility capacity of almost 4,300 Bcf. Depending on storage levels at Withdrawal charges for the removal of gas from storage • the end of the previous winter, and the temperatures over the Injection charges for the injection of gas into storage • injection season, U.S. working gas in storage will generally be A salt cavern, with its ability to turn over inventory frequently - when full percent 90 and 80 between official sea winter the and quickly, allows for additional uses, enabling users to cap - son begins on November 1. ture extrinsic value. Many salt dome facilities can cycle be- tween injection and withdrawal at almost a moment’s notice, Storage Service and Uses - giving users capac greater flexibility. Entities leasing storage ity may move gas in and out of storage as prices change in - Approximately 120 entities – including interstate and intra may attempts profits to or minimize costs. Storage maximize state pipeline companies, LDCs and independent storage ser- be a component in producer or consumer hedging strate - vice providers – operate the nearly 400 underground storage gies, helping them to manage the risk of price movements. facilities active in the continental United States, according to | C egulatory r nergy e ederal F ommission Energy Primer 30

37 covers and the maximum daily quantity that may be injected or withdrawn. Energy marketers have increasingly used these It facilities as they try to profit - at also is volatility. price from tractive to shippers, industrial consumers with uncertain loads and gas-fired generators whose needs change rapidly. firm both service, storage offer Pipelines also - interrupt and ible, 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 usa ge com ponents for firm service and a usage compo - nent for interruptible. Market Effects Storage can mitigate large seasonal price swings by absorbing natural gas during low demand periods and making it avail - able when demand rises. Further, storag e 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 Further, storage helps shippers avoid system imbalances and reduce to tend levels storage Higher weather. forward prices; associated penalties, and supports swing gas supply services, lower storage levels tend to increase them, all other market are short-term contracts that provide which flexibility when conditions being equal. either the supply of gas from the seller, or the demand for gas from the buyer, are unpredictable. Storage also facilitates title FERC Jurisdiction transfers and parking and lending services. This helps shippers - balance daily receipts and deliveries, manage their overall sup The underground storage of natural gas has historically been - ply portfolio or take advantage of price movements. Conse critical in assuring that the needs of natural gas customers are operators have begun offering a more varied quently, storage met. The Energy Policy Act of 2005 added a new section to the menu of services, and users have begun using storage as a stating that Natural Gas Act authorize the Commission may commercial tool and as part of a comprehensive supply port- natural gas companies to provide storage and storage-relat- folio strategy. ed services at market-based rates for new storage capacity, Merchant storage, frequently using salt caverns, uses market- even though the company cannot demonstrate it lacks mar- recognizing prices, based value at any dynamics the affecting 717c(f)). authorization, this make o T the § U.S.C. (15 power ket given point in time. Prices often take into account the prices - FERC must determine that market-based rates are in the pub at which the Nymex futures contracts are trading. They may lic interest and are needed to encourage the construction of number the storage volume, the also of times the gas reflect new capacity, and that customers are adequately protected. will be cycled, the length of the contract and the timeframe it | Energy Primer 31

38 hedging profit their protect to thei and production own r ing Natural Gas Markets and Trading margin from these sales. categories five are there speaking, Generally marketing of - The natural gas industry in the United States is highly competi producer marketers, companies: major integrated nationally tive, with thousands of producers, consumers and intermedi - marketers, small geographically focused marketers, aggrega - ate marketers. Some producers have the ability to market tors and brokers. their natural gas and may sell it directly to LDCs, to large in - dustrial buyers and to power plants. Other producers sell their of range full The a offer marketers integrated nationally major gas to marketers who aggregate natural gas into quantities market numerous services, and products. They oper - different the fit that then trans - of types and different of buyers needs ate on a nationwide basis and have large amounts of capital port the gas to their buyers. to support their trading and marketing operations. Producer marketers are those entities generally concerned with selling Most residential and commercial customers purchase natural their own natural gas production or the production of their gas from a LDC. In contrast, many industrial customers and gas production affiliated Smaller market - natural company. most power plants have the option to purchase natural gas and ers specific gas natural particular target geographic areas from a marketer or producer instead of from the LDC, thereby marketing Many markets. affiliated with LD Cs are of entities avoiding any LDC charges. this type, focusing on marketing gas for the geographic area Interstate pipelines do not buy and sell natural gas and are distributor operates. Aggregators gen - which in their affiliated limited to providing transportation and storage services only. erally gather small volumes from various sources, combine As noted, interstate pipelines transport natural gas at rates them, and sell the larger volumes for more favorable prices approved by the FERC. and terms than would be possible selling the smaller volumes separately. Brokers are a unique class of marketers because Natural Gas Marketers they never take ownership of natural gas themselves. They simply act as facilitators, bringing buyers and sellers of natural Most gas trading in the United States is performed by natural gas together. gas marketers. Any party engaging in the sale of natural gas backroom All marketing companies must have significant can be termed a marketer; however, marketers are usually - operations in addition to the core trading group. These sup specialized business entities solely in transacting to dedicated coordinating port everything related staff are re sponsible for the physical and financial energy markets. It is commonplace purchase and sale the to and gas, natural financial physical of for natural gas marketers to be active in a number of energy including arranging transportation and storage, posting com - markets, taking advantage of their knowledge of these mar - pleted transactions, billing, accounting and any other activity kets to diversify their business. that is required to complete the purchases and sales arranged Marketers can be producers of natural gas, pipeline market- by the traders. - independent affiliates, C LD affiliates, ing marketing market traders e th to - addition In and backroom staff, marketing com gas. natural of users large-volume or institutions, financial ers, panies typically have extensive risk-management operations. services, of range full a offer may companies marketing Some The risk-management team is responsible for ensuring that marketing numerous forms of energy and financial products, the traders do not expose the marketing company to exces- while others may be more limited in their scope. For instance, sive risk. producers firms - nat sell not do with affiliated marketing most - ural gas from third parties; they are more concerned with sell | C r nergy e egulatory ederal F ommission Energy Primer 32

39 at - Flor the to basis the and Hub Henry the price the be would ida hub. Physical Trading of Natural Gas Natural gas contracts are negotiated between buyers and sell- ers. 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 day) days number of terms other and beginning specified a on - and conditions. The special terms and conditions usually out Market Hubs line such things as the payment dates, quality of the natural gas to be sold, and other specifications agreed to by both any - through gas Natural is priced and traded at different locations parties. out the country. These locations, referred to as market hubs, exist across the country and are located at the intersections of Natural gas contracts are negotiated between buyers and sell- major pipeline systems. The price at which natural gas trades ers over the phone or executed on electronic bulletin boards supply and differs across th e major hubs, depending on the and e-commerce trading sites. The points. particular the at gas ural nat for demand difference of There swing contracts: gas natural types main three are is hub another and price the called Hub Henry the between contracts: baseload contracts, contracts, and firm differential, or basis. location In - oth hubs, market to addition er major pricing locations include citygates. Citygates are the Swing (or interruptible) contracts are usually short-term • locations at which distribution companies receive gas from a contracts between one day and a month in length. These centers metropolitan can - an major at Citygates pipeline. offer and are flexible, are usually put in most the contracts other point at which natural gas is priced. place when either the supply of gas from the seller, or the demand for gas from the buyer, are unreliable. benchmark country’s the being the to addition In Henry hub, • Baseload contracts are similar to swing contracts. Neither point is also the delivery Hub for the Nymex natural gas fu - the buyer nor seller is obligated to deliver or receive the at contract. provide Hub Henry the a price in Changes tures is both exact volume specified. However, it agreed that good indicator of how prices are generally changing across the receive or deliver to attempt will specified parties the country. a basis. best-efforts on volume, contracts are different from Firm swing and baseload con - • re usually Basis to cost transport variable gas be - the flects tracts in that both parties are legally obligated to either tween change, can Basis hub. another and Hub Henry the of - or deliver the amount receive gas specified in the con sometimes dramatically, depending on local market condi - tract. These contracts are used primarily when both the tions, and can widen considerably when pipelines between of specified natural amount supply and demand for the two points are congested. Basis in excess of transportation gas are unlikely to change. costs results from pipeline constraints and lack of pipeline competition. The gas price at a hub in Florida, for example, | Energy Primer 33

40 using fixed-price contracts (or are prohibited from them by Price Discovery state or local regulators). Spot (Cash) Market The Financial Market The U.S. natural gas marketplace has a highly competitive physical In addition to trading natural gas, there significant is a spot, or cash, market where brokers and others buy and sell in and market for natural gas instruments financial derivatives - natural gas daily. The daily spot market for natural gas is ac In States. United the participants market market, financial the tive, and trading can occur 24 hours a day, seven days a week. movement interested in profiting from the are of the price of The map on the next page shows some of the points where natural gas rather than delivering or receiving natural gas. The natural gas for next-day physical delivery is actively traded on and settlement of to pricing these financial products tied are the IntercontinentalExchange (ICE). Some of these points are physical natural gas. It is estimated that the value of trading market centers, where brokers actively trade and prices are on occurs that financial the market is at least a times dozen established. In addition to these market centers, natural gas greater than the value of physical natural gas trading. is actively traded at many other locations, including segments of individual pipelines and locations where pipelines intercon - financial instru ments that derive their value are Derivatives nect with LDCs. from an underlying fundamental – in this case, the price of natural gas. Derivatives can range from being quite simple to Spot market transactions are normally conducted on electron - being exceedingly complex. Traditionally, most derivatives are ic exchanges or by telephone, with the buyer agreeing to pay - traded on the over-the-counter (OTC) market, which is essen a negotiated price for the natural gas to be delivered by the tially a group of market players interested in exchanging cer - on a specifi ed seller delivery poi nt at the next day. Natural gas tain derivatives among themselves. prices reflect daily supply and spot can and balances demand be volatile. Chapter in appears 5. financial More information on markets Bidweek business days of a is Bidweek the name given to five last the Hubs for Physical Trading on ICE month. This is the week when producers sell their core pro- duction and consumers buy natural gas for their core needs for the upcoming month. Index Prices - Several publications, such as Platts Gas Daily, Natural Gas In telligence 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 re- port their bidweek prices to publications, which convert these prices into monthly locational price indexes that are available Source: Derived from Intercontinental Exchange data day on the first business day following the last of bidweek. These daily and monthly indexes, in turn, are used as the basis that pricing for those firms into do not choose to enter for | C r nergy e egulatory ederal F ommission Energy Primer 34

41 3. W E lEctricity m arkEts holEsalE 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. to authorizes and reviews or cost- rates market-based at sell based rates. Quick Facts: Measuring Electricity - sup driving factors In competitive markets, prices reflect the Electricity is measured in terms of watts, typically in kilo- ply and demand – the physical fundamentals. Where rates watts (1,000 watts) or megawatts (1,000 kilowatts). are set based on costs, market fundamentals matter as well affect consumers because will in supply and demand changes A kilowatt (or watt or megawatt) is the amount of en- and electricity. Supply in - the influencing by of reliability cost ergy used, generated or transmitted at a point in time. corporates generation and transmission, which must be ad- The aggregation of kilowatts possible at a point in time - equate to meet all customers demand simultaneously, instan for a power plant, for example, is its capacity. The aggre - taneously and reliably. gation of kilowatts used at a point of time is the demand at that point. affect supply key Consequently, factors that fuel include prices prices, capital costs, transmission capacity and constraints and The number of kilowatts used in an hour (kilowatt-hour the operating characteristics of power plants. Sharp changes or kWh and, in larger quantities, megawatt-hour or MWh) well in demand, as demand, as extremely high affect levels of is the amount of electricity a customer uses or a power prices well, especially if as less-efficient, more-expensive pow - plant generates over a period of time. er plants must be turned on to serve load. 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 even tually 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 address - es retail demand and other instances where retail markets wholesale markets. strongly influence 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 whole- markets, authorizes either FERC entities sale jurisdictional | Energy Primer 35

42 Economies of Scale Electric Power Industry Electric power is one of the most capital intensive industries. Generation alone can account for roughly 65 percent of a Electricity on Demand ing Spread customer’s electric bill. costs fixed these relatively over more customers helps bring down the cost that each cus - - In the United States and other developed countries, consum tomer pays. ers expect electricity to be available whenever they need it. - Electricity use has grown enormously as consumers now con Thomas Edison’s first street lighting project in the 1880s sider not only refrigerators, TVs and hair dryers but also com - grew to electrifying whole neighborhoods, towns and cities. puters and other electronic devices as necessities. Consumers - Providing service over larger areas allowed utilities econo also expect to pay reasonable prices for the electricity they mies of scale in generating technology. The cost per unit of use. production dropped as power plants grew larger and larger. The companies building these facilities were basically self- Meeting these customer expectations is challenging. With - contained – they owned and operated the generation, trans few exceptions, electricity cannot be stored in any appre- mission and distribution facilities. Power lines were built from ciable quantities, and thus must be produced as needed. Fur- their generation to their population, or load, centers. These ther, unlike most other markets, electricity’s historical inelas - companies were vertically integrated. tic demand does not move with prices. To provide electricity on demand, electric system operations have to be planned is that they are One downside of larger generating units diffi - and conducted with that goal in mind. Lacking storage and cult to replace if they experience unexpected shutdowns. For responsive demand, operators must plan and operate power a single utility building a new and larger unit, the only way to plants and the transmission grid so that demand and supply ensure reliable service is to build two units – creating a capac - exactly match, every moment of the day, every day of the ve. reser ity unit nuclear and coal sizes grew to 500 or When year, in every location. 1,000 MW, building two units became very expensive for any individual company. The Drive for Enhanced Value Reserve Sharing, Interconnection and The electric industry has met this growing demand with in - Power Pools Between 1929 creasing and 1967, efficiency. the national av - erage cost of electricity for residential customers plummeted The solution to high reserve costs was to share reserves with remains and dollars), 2005 from (in 10¢/kWh to 60¢/kWh about adjacent utilities. Instead of building two large units, utilities there to day. How did the achieve such tre - around industry could buy from their neighbors in times of need, and cut their - mendous cost savings and then keep the real price of electrici nificantly. sig reserve costs built utilities sharing, facilitate o T by be can Part years? greater 40 past the over flat ty explained major interconnecting transmission lines large enough to de- new techniques efficiency – power plants use less fuel, and liver power in case of a major generator outage. Today’s bulk make it cheaper to extract the coal and natural gas that fuels power grid began as a way to maintain reliable service while generators. Another part of the answer, though, stems from lowering costs. is industry the way the in changes operated. and organized 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 | C egulatory r nergy ommission ederal F e Energy Primer 36

43 - With the transmission interconnections in place, northwest ern 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 pro - vide for a lively bilateral trading market. In the 1960s, the electric power industry created an informal, operating voluntary organization of staff to aid in coordinat - ing 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, the to led blackout The people. million 30 - develop affecting ment in 1968 of the National Electric Reliability Council, short - ly 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 FERC of Act Policy Energy U.S. the in as NERC certified 2005, States, United the and for organization the electric reliability reliability standards became mandatory and enforceable. Optimizing Unit Commitment and Economic Dispatch pools, the forerunners of today’s regional transmission orga - nizations. - The industry also reduced costs by using computers and com Coordinating exchanges of energy and reserves also led to to munication system - Utili operations. optimize nology tech - closer coordination of other utility functions, such as the pro of their commitment the ties use algorithms for optimizing cess of determining which generating units to use, called unit generating units, while day-ahead market software does this commitment. Operators want to commit just enough capacity transmission bi for supp liers organization dding into regional to ensure reliability, but no more than is needed. This began a markets. new phase of using economies of scale in system operations In real time, demand is changing all the time. Without storage encompassing whole regions of the country. and responsive demand, the output of some generators must Regional coordination also was spurred by special circum - change to follow constantly changing demand. This is known stances, particularly in the West. Large federally owned dams economic dispatch to optimize use as load following. Utilities on the Columbia and Colorado rivers generate power from the of use the minimize real-time costs. units these and snow. runoff of melting mountain spring When the reservoirs are full and the turbines are spinning, there is not enough Economy Energy Trade local demand to use the power. Since the hydropower was Source: Energy Velocity cheaper than any alternative, long distance transmission lines Since transmission interconnections were built primarily for were built to deliver the excess power from the Northwest the rare need to deliver reserves in emergencies, the industry and Southwest to load centers in California. | Energy Primer 37

44 had excess transmission capacity. This allowed utilities to use Evolving Public Policies lines to trade power. Major utilities generally owned suffi - the capacity to meet their own peak power cient needs. However, policy theories - pow the Different public electric have shaped sometimes the cost of operating their marginal generation er industry over its history. All of these public policies are still was higher or lower than that of their neighbors. Transmission in play to some extent today. Five concepts that helped shape availability provided opportunities for utilities to save money the electricity industry and markets are outlined next. by buying energy when it was cheaper than generating and - selling energy to utilities with higher costs. This is called econ Not-for-Profit Utilities omy energy trading. ensuring to approaches first value was customer One of the depend on n onprofit electric to providers. In the early days in started In cities. and towns of the industry, electrification many places, this utility service was provided by the municipal government. The federal government stepped in to develop nation’s and market the signi ficant hydroelectric resources. - relied program electrification rural on cus The Depression -era tomer-owned rural electric cooperatives and low-interest gov- ernment 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 investor- owned regulated monopolies. In the early days of the indus - try, while many cities went the municipal route, many inves- tor-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 mo nopolies. 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 inte - grated resource planning (IRP) processes to determine what facilities should be built. | C egulatory r nergy ommission ederal F e Energy Primer 38

45 - out to be higher than the actual costs avoided by the purchas Power Pools utility. ing The rapid growth and size of the QF industry sur - prised many policymakers and entrepreneurs, and got them Power pools are multilateral arrangements with members thinking about the viability of generation independent of reg - ceding operational control over their generating units and ulated monopolies. - transmission facilities to a common operator. Members pro vided incremental cost data about their units and system - In 1988, FERC proposed rules to allow states to set their avoid - status data to the operator. The operator ran an energy man ed-cost rate based on an auction. Instead of taking all capacity to data cost agement system that unit on the optimize used at a set rate, states could set the rate based on bids to supply a a multilateral basis unit commitment and economic dispatch. certain amount of needed capacity. The Commission also pro- posed to open the avoided-cost auction up to independent PJM began in 1927 for utilities to share their generating re- power producers (IPPs) that did not qualify as QFs. In this ork Y New The sources, pool. power first world’s the forming - way, a regulatory program was transformed into a competi Power Pool was formed in 1966 and the New England Power tive initiative. Pool in 1971 in response to the 1965 Northeast blackout. The - Electric Reliability Council of Texas (ERCOT) and the South Under the regulated monopoly model, utilities owning and op - west Power Pool (SPP) formed in 1941 to pool resources for erating transmission lines had no obligation to allow others to effort. war the development the barrier significant to use them. This posed a of an independent power industry. The Commission started Competition, Part 1: Competitive Generation conditioning approval in merger cases with the voluntary pro- and Open Access vision of open transmission access. The Energy Policy Act of - 1992 gave the Commission authority to grant transmission ac The environmental movement and initiatives to open the air- cess on request. These approaches to open access resulted in line and trucking industries to competition helped shape the patchwork transmission access. energy industry in the 1970s. A provision in President Carter’s By the mid-1990s, support for opening the transmission grid energy plan led to passage of the Public Utility Regulatory to all users encouraged the Commission to pursue a generic Policies Act of 1978 (PURPA), which ushered in the next era. - solution. Order No. 888 required mandatory open transmis PURPA established a program implemented by states and sion access by all transmitting utilities and a reciprocity provi - use of efficient cogen overseen - by the FERC to encourage the sion successfully extended open access to non-jurisdictional eration (using the heat from industrial or other processes to entities (municipal, cooperative and federal utilities). generate electricity) and small scale renewable generation. Order No. 889 addressed matters needed to implement open FERC’s role was to issue regulations for the program and cer- access. The rule established the Internet-based Open Access tify that qualifying facilities (QFs) met statutory requirements. Same-Time Information System (OASIS) for posting avail- States administratively set the price to be paid to these gen - able transmission capacity and reserving transmission capac - erators at the cost the utilities would avoid by purchasing the changes significant control utility to ity. These rules required power rather than generating it themselves. room operations and limited the ability of companies to share - Most states set their avoided cost rate so low that they got lit transmission-related information with their own power mar- Califo rnia, T exas and Massachusetts QF ca However, tle pacity. keting operating units. set very generous avoided cost rates and were overwhelmed with QF capacity, much of which received prices that turned | Energy Primer 39

46 North American Independent System Operators and Regional Transmission Organizations Source: Velocity Suite, ABB transmission systems and develop innovative procedures to Competition, Part 2: Integrating Markets manage transmission equitably. The Commission’s proceed- and Operations – RTOs efforts the with along 2000, and 888 Nos. Orders in ings of industry, the organization voluntary the to led and states the While the industry had historically traded electricity through of ISOs and RTOs. Each of the ISOs and RTOs subsequently bilateral transactions and power pool agreements, Order No. developed a full scale energy and ancillary service market in 888 promoted the concept of independent system operators or for bid The buyers could sellers and generation. offer which (ISO). Along with facilitating open-access to transmission, an ISOs and RTOs used the bid-based markets to determine eco - ISO would operate the transmission system independently nomic dispatch. Throughout the subsequent sections of the of, and foster competition for electricity generation among, primer, the term RTO is used to stand for both ISOs and RTOs. wholesale market participants. Several groups of transmis - sion owners formed ISOs, some from existing power pools. Major parts of the country operate under more traditional market structures, notably the West (excluding California) Close on the heels of Order No. 888, the Commission, in Order and the Southeast. Notably, two-thirds of the nation’s elec - No. 2000, encouraged utilities to join regional transmission tricity load is served in RTO regions. operate the organizations (RTO) which, like an ISO, would | ederal e nergy F r egulatory C ommission Energy Primer 40

47 - far northern areas of the United States, where air condition Electricity Demand peak seasonal Florida’s South significant. not is load ing also occurs during the winter, when the population and tourism Americans use electricity for heat and light, to run machinery surges. and to power a growing number of products such as televi- - Daily demand typically peaks in the late afternoon, as com sions, radios, computers, hair dryers, and cell phones. This mercial and domestic activities peak, and, in the winter, when use has been increasing, reaching over 3,860 gigawatt-hours lighting needs grow. (GWh) of electricity in 2014. Demand dropped in 2009 with the recession, but has since recovered. Subsequent to the reces- Electricity use also varies between weekdays and weekends. sion, been the trend in use has flatter. Commercial and industrial activities are lower on weekends and peoples’ noncommercial activities change with their The bulk of the electricity generated is sold to consumers, personal can also weekdays different on load The schedules. known as end-users or retail customers. Some consumers being Fridays, and Mondays e, exampl For differently. behave generate some or all of the power they consume. Some of the to adjacent loads have different uesday T may than weekends, electricity sold to retail consumers is generated by integrated through Thursday. This is particularly true in the summer. investor-owned utilities, federal entities, municipally owned and co-operatively owned utilities that sell the power directly Because demand historically has not varied with price and be- to consumers. The rest of the electricity ultimately consumed cause storage options are limited, generation must rise and fall by retail customers is bought and sold through wholesale to provide exactly the amount of electricity customers need. electricity markets. The cost of providing power typically rises as demand grows, and falls as demand declines, because higher levels of demand Demand Characteristics require activation of increasingly more expensive sources of power generation, and reductions as demand declines. As a peak. or baseload as characterized often is Demand Baseload result, power prices are typically highest during periods of is demand that occurs throughout the day or throughout the peak demand. This causes system planners, power marketers year. Refrigerators, for example, may create baseload de - and traders to all carefully track weather trends, economic mand. Peak load is demand that shows up during part of the growth and other factors to forecast power demand. day or year, all at the same time – heating or air conditioning, for example. Demand Drivers The amount of electricity consumed (demand) is continuously In general, the amount of electricity demanded is relatively varying and follows cycles throughout the day and year. Re- insensitive to the price of electricity in the short-term (inelas - gionally, electric demand may peak in either the summer or tic). One reason for this is that many customers – especially the winter. Spring and fall are typically shoulder months, with smaller customers – do not get price signals to which they can lower peak demand. Seasonal peaks vary regionally, although respond. Most residential customers are billed monthly on a the highest levels of power load in almost all regions of the preset rate structure. Large industrial customers, on the other United States occur during heat waves, which are most acute hand, may receive real-time price signals. - during the daily peak load hours that occur during the late af their reach regions of minority a However, ternoon. load peak Further, electricity is a necessity to most people and busi - when the weather is extremely cold. These are primarily areas nesses. While they may be able to reduce their demand in the sig nificant space-heating and little summer with requirements turning off or short-term – by turning down the thermostat air conditioning load. A majority of these systems are in the | Energy Primer 41

48 to Weather for example – electricit y consumers find it difficult lights, also - electric on effects short-term extreme have can ity usage. A sudden cold snap can drive heating use up quickly do without electricity altogether. There is little storage for and a heat wave can push air conditioning loads. Other, less electricity now and few realistic substitutes. Consequently, demand affect for wind, and rain – demand tends to drive price, especially when the system is patterns weather obvious cooling, example, result in sudden may affecting heating or stressed. air conditioning. In the longer-term, options for reducing electricity use include - switching to natural gas, installing insulation and implement Economic Activity energy efficiency ing measures. other Larger consumers may consider building their own generation facilities. The - electric of cycle the affects pattern socioeconomic of life use, - pat different with weekends and ity ho lidays showing a Governments and businesses are also developing demand-re- tern than weekdays. Demand typically rises as people wake up sponse programs, which may provide reduced rates or other and go to work, peaking in the afternoon. compensation to customers who agree to reduce load in peri- ods of electric system stress. de - The level of economic activity also affects power overall mand. During periods of robust activity, loads increase. Simi - Factors driving demand include demographics, climate and larly, loads drop during recessions. These changes are most weather, economic activity and policies and regulations. evident in the industrial sector, where business and plants to may clo se, downsize or elimina te factory shifts. In addition Demographics reducing overall demand, these changes may affect the pat - tern of demand; for example, a factory may eliminate a night with Population leve ls affect demand, population greater shift, cutting baseload use but continuing its use during peak levels tending to increase electricity consumption. Shifts in effects cases some In hours. significant. be can these Population affect population in flight also demand. regional the 1980s from northern industrial regions – the Rust Belt residential con - – to warmer climates in the South affected sumption patterns. In the 1990s, consumption in the South surpassed that in the Midwest, making it the region with the Quick Facts: Heating and Cooling Degree Days greatest electricity use. In the United States, engineers developed the concept of degree days effects the measure to and cooling heating Climate and Weather of temperature on demand. Average daily temperatures are compared to a 65°F standard - those in excess of 65° Weather is one of the primary factors driving demand. Gen - yield cooling degree days; those below 65° yield heating eral climatic trends drive consumption patterns and there - degree days. A day with an average temperature of 66° fore the infrastructure needed to ensure reliable service. Cold would yield one cooling degree day. - weather and short days drive winter demand in northern re gions. 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. | C egulatory r nergy e ederal F ommission Energy Primer 42

49 social facilities. Energy Policies and Regulations More than half of commercial consumers’ electricity use is for prices and policies affecting re set agencies regulatory State - heating and lighting. tail customer service. Some states are considering changes that would enable customers to receive more accurate price Industrial consumers use about 27 percent of the nation’s signals. They include, among other things, changing rate electricity. This sector includes, for example, manufacturing, structures so that the rate varies with the time of day, or is construction, mining, agriculture and forestry operations. In - even linked to the cost of providing electricity. dustrial customers often see the their reflecting rates, lowest ability their and structure load flat relatively at service take to overall by Efforts - reduce effi demand energy improving to higher voltage levels. ciency are underway through several governmental and utility venues. for electricity stems primarily from Transportation demand trains and urban transportation systems. This is less than 1 percent of electricity demand. Retail Customer Mix Most electric serve - resi utilities of types different customers: Load Forecasting dential, commercial and industrial. Each class uses electricity differently, amount the or profile, load differing a in resulting Demand is constantly changing, challenging grid operators that each customer class uses and the daily shape of the load. and suppliers responsible for ensuring that supply will meet If a consumer uses electricity consistently throughout the day demand. Consequently, they expend considerable resources load shape is flat, and the load will be base - and seasons, th e to forecast demand. Missed forecasts, where actual demand load. Another consumer may use more at some times than the differs significantly from forecast, can cause wholesale others, resulting in baseload and peaks. Greater variability prices to be higher than they otherwise might have been. in demand is typically more expensive to serve, especially if Forecasts are necessary as well for the variety of actions that the peak occurs at the same time other customers’ use peaks. - must occur if sufficient supply is to be available in the immedi affects a region’s Consequently, the mix of customer types planning or long term: ate the long-term infrastructure needs overall demand. supplies other and staffing, of the system, purchasing fuel and form the largest customer segment in Residential consumers for example. Load forecasts are also extremely important for the United States at approximately 37 percent of electricity other and institutions suppliers, cial finan - elec in participants - demand. Residential consumers use electricity for air condi tric energy generation, transmission, distribution and trading. tioning, refrigerators, space and water heating, lighting, wash- Load forecasting uses mathematical models to predict de- ers and dryers, computers, televisions and other appliances. mand across a region, such as a utility service territory or RTO service highest, typically are ential resid for Prices reflecting three into divided be can categories: footprint. Forecasts both their variable load shape and their service from lower- short-term forecasts, which range from one hour to one week voltage distribution facilities, meaning that more power lines ahead; medium forecasts, usually a week to a year ahead; and are needed to provide service to them. long-term forecasts, which are longer than a year. It is pos - is the next largest customer segment at ap - Commercial use sible to predict the next-day load with an accuracy of approxi - 36 percent, and in cludes office buildings, hotels proximately mately 1 to 3 percent of what actually happens. The accuracy and motels, restaurants, street lighting, retail stores and of these forecasts is limited by the accuracy of the weather wholesale businesses and medical, religious, educational and forecasts used in their preparation and the uncertainties of | Energy Primer 43

50 The programs may use price signals or incentives to prompt human behavior. Similarly, it is impossible to predict the next customers to reduce their loads. The signals to respond to year peak load with the similar accuracy because accurate electric power system needs or high market prices may come long-term weather forecasts are not available. from a utility or other load-serving entity, an RTO or an inde - for The forecasts are different time horizons for important pendent DR provider. These programs are administered by different operations within a ut ility company. Short-term load both retail and wholesale entities. forecasting can help to estimate transmission system power flows of and to make decisions that can prevent overloading transmission systems. Timely implementation of such deci - sions leads to the improvement of network reliability and to the reduced occurrences of equipment failures and blackouts. Forecasted weather parameters are the most important fac - tors 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 custom er 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 sys - tem infrastructure planning and are meant to ensure that DR has the potential to lower systemwide power costs and as - of there are sufficient resources available to meet the needs sist in maintaining reliability. It can be used instead of running the expected future peak demand. These forecasts are made power plants or to relieve transmission congestion. There can for periods extending 10 to 20 years into the future. to tend units because benefits environmental be also peaking be costly - and dirty - to run. Demand Response Demand response rewards consumers for reducing load dur - Electricity demand is generally insensitive to price, meaning at specific conditions However, times. ing certain market and that demand does not typically fall when wholesale prices reduction. this Measuring quantify it is to measure and difficult rise. This occurs for several reasons, including that most end - and verifying the reduction requires development of consum use consumers of electricity are not exposed to real-time elec- ers’ baseline usage, against which their actual use is measured utilities some However, operators prices. tricity are grid and to determine the reduction in the event they are called to developing ways to stimulate a response from consumers lessen their load. An accurate measure of their typical usage is through demand-response programs. important to prevent (or detect) gaming by participants. Demand response (DR) is the reduction in consumption of Demand-Response Programs electricity by customers from their expected consumption in - response to either reliability or price triggers where the cus Programs gene into three categories: curtailing, shift - fall rally tomer forgoes power use for short periods, shifts some high ing or on-site generation. energy use activities to other times, or uses onsite generation. | C egulatory r nergy e ederal F ommission Energy Primer 44

51 - time to price or other signals. These models may allow cus or forgoing, involves reducing power use (load) Curtailing, tomers to respond more easily as they require little customer during times of high prices or threats to reliability without monitoring or interaction. making up the use later. For example, residential customers or raise th ermostats might during hot weather. turn off lights turn off Commercial equipment, lower office fac ilities may Demand Response in Retail Markets building lighting or change thermostat settings by a few de- grees. DR use energy efficiency, or Many states re quire utilities to Resource Efficiency Energy resources. renewable Standards involves moving or rescheduling high energy-use Shifting (EERS) in more than half of the states require utilities to activities in response to high prices or DR program events to achieve electric energy savings; many of these standards in - nights or weekends. Industrial off-peak periods – evenings, clude peak load reduction targets. These mandates provide customers might reschedule batch production processes to incentives for utilities to reduce customers’ energy consump - evening hours or the next day. Commercial establishments mechanisms as such tion, from the profits decouple that may delay high-energy operations. Residential customers may amount of electricity sold, or performance bonuses for utili - - wait until evening or night to use high-energy consuming ap ties that meet or exceed reduction targets. pliances, such as clothes dryers or dishwashers. In shifting, the lost amenity or service is made up at a subsequent time. Some states are implementing dynamic pricing, in which retail reflect costs. Time- rates change frequently to better system On-site generation is when some customers may respond by based rates depend on advanced meters at customer premis- - turning on an on-site or backup emergency generator to sup es that can record usage. In time-of-use programs, customers ply some or all of their electricity needs. Although customers are char ged different prices at different times, with hours of may have little or no interruption to their electrical usage, hours. off-peak peak demand costing more than their net load and requirements from the power system are reduced. The ability to use on-site generation is most common In real-time pricing (RTP) programs, customers are charged for institutional customers, such as hospitals, large schools or or Industrial power. of cost the immediate reflecting prices data centers. are tariffs. RTP very large commercial customers on often DR programs can be further distinguished by whether they Critical peak pricing (CPP) uses real-time prices at times of are controlled by the system operator (dispatchable) or the extreme system peak, and is restricted to a small number of customer (nondispatchable). Dispatchable demand response hours annually but features prices higher than time-of-use refers to programs that reduce customer energy use, such prices during the critical peak. Consumers do not know in ad- as direct load control of residential appliances or directed vance when a critical peak might be called. A CPP program for reductions to industrial customers. Dispatchable DR is used stick: the customers residential critical- uses a carrot without for reliability or economic reasons. Nondispatchable demand peak rebates. Participating customers get rebates on their response lets the retail customer decide whether and when bills for responding to utility price-signals, but are not penal - to reduce consumption in response to the price of power. It hours. ized if they do not lower use in those includes time-sensitive pricing programs based on rates that charge higher prices during high-demand hours and lower Wholesale Market Programs prices at other times. Retail programs may aid RTOs, although the RTO may not As a result of technology innovations and policy directions, amount see the be able to invoke them or even specifically - new types and applications of DR are emerging that encom of response that occurs. Wholesale-level DR occurs in the pass the use of smart appliances that respond in near real- | Energy Primer 45

52 (DRR) or groups of residential customers. In aggregating small cus which differ in how demand-response resources - RTOs, tomers, CSPs have increased customer participation in many may participate in their markets. Some RTOs permit DRR to participate in their markets as voluntary reliability resources. wholesale reliability and emergency programs. DRR also can participate in wholesale electricity markets as capacity resources and receive advance reservation payments Demand-Response Use in Planning and in return for their commitment to participate when called. Re - Operations to perform when called penalized. are Addi - sources that fail tionally, some DRR bids into RTO day-ahead (DA) markets as can sup - times to Different DR programs be used at various energy resources, specifying the hours, number of megawatts (see operations graphic). port and nning efficiency Energy pla - and price at which they are willing to curtail. RTOs set mini programs that reduce baseload or peak demand over the mum bid values. - long-term are incorporated into system planning. Dispatch able programs that are quickly implemented and targeted for Some of the RTO DR comes from individual entities; the rest is short-term peak reductions – such as direct load control – lie accumulated through third-party aggregators, or curtailment on the other end of the spectrum, and are used in the moment service providers (CSPs), who recruit customers too small to of operation. participate on their own, such as schools, commercial chains Demand-Response Program Use in Electric System Planning and Operations Source: U.S. Department of Energy | C egulatory r nergy ommission ederal F e Energy Primer 46

53 FERC as the nation’s energy which and organization reliability Electricity Supply and Delivery develops standards, among other things, to ensure the grid’s reliability. The standards, once approved by FERC, must be Unlike many other products, electricity cannot be stored in met by all industry participants – the standards are mandatory any appreciable quantities. Further, electricity is a necessity - and enforceable. Consequently, the grid is designed and oper - for most consumers, whose use responds little to price chang ated to meet these standards. es. Finally, electric equipment and appliances are tuned to a include: regions NERC’s standard Devia very specific - of power, measured as voltage. tions in voltage can cause devices to operate poorly or may Florida Reliability Coordinating Council (FRCC) • even damage them. Consequently, the supply side of the elec- (MRO) Organization Midwest • Reliability tricity market must provide and deliver exactly the amount Northeast Power Coordinating Council (NPCC) • of power customers want at all times, at all locations. This re- Reliability First Corporation (RFC) • quires constant monitoring of the grid and close coordination SERC Reliability Corp. (SERC) • among industry participants. Southwest Power Pool (SPP) • Texas Reliability Entity (TRE) • Electricity service relies on a complex system of infrastructure Western Electricity Coordinating Council (WECC) • into gories: cate general two falls that and the de - generation livery services of transmission and distribution. Together, the power generation and high-voltage transmission lines that NERC Regions 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: North American Electric Reliability Corporation Generation Source: National Energy Education Development Project Nationally, the grid is split into three main sections – the by they fuel the Power generators are typically categorized Western, Eastern and Texas Interconnections. These sections use their - specific operating technolo and subcat egorized by - operate independently and have limited interconnections be gy. The United States has more than 1,000 gigawatts (GW) of tween them. total generating capacity. Coal, natural gas and nuclear domi - nate the power generation market. The nation, along with Canada and a small part of Mexico, is also divided into regional entities. The regional reliability enti- char - and Power operational plants each have differing costs ties fall under the purview of NERC, which was designated by acteristics, both of which determine when, where and how | Energy Primer 47

54 older plant designs became a source of concern following plants will be built and operated. the accident at the Three Mile Island plant in the United capital categories: investment Plant costs fall into two general States in 1977, the Chernobyl plant meltdown in Ukraine in - costs, which are amounts spent to build the plant, and opera 1986 and the Japanese earthquake, tsunami and nuclear tional costs, the amounts spent to maintain and run the plant. plant destruction in 2011. New plant designs have been the expenses: In general, there is a trade-off between these - put forward and a few are under construction. The dispo most capital intensive plants are the cheapest to run – they sition of high-level radioactive waste remains an unre - have the lowest variable costs – and, conversely, the least solved problem, and the waste remains at plant locations. capital intensive are more expensive to run – they have the highest variable cost. For example, nuclear plants produce Conventional Generation - vast amounts of power at low variable costs, but are quite ex build. Natural gas-fired combustion turbines are far pensive to Natural gas power plants feature three major technologies, less expensive to build, but are more expensive to run. - each with its distinct set of market advantages and limita tions. They are steam boilers, gas turbines and combined cycle Grid operators dispatch plants – or, call them into service – generators. Natural gas fuels nearly a third of electricity gen - with the simultaneous goals of providing reliable power at eration. the lowest reasonable cost. Because various generation tech- plants are dispatched nologies have differing variable costs, Steam boiler technology is an older design that burns gas in only when they are part of the most economic combination of a large boiler furnace to generate steam at both high pres - plants needed to supply the customers on the grid. For plants sure and a high temperature. The steam is then run through operating in RTOs, this cost is determined by the price that a turbine that is attached to a generator, which spins and by the mar - is areas, other In offer. determined generators it ranges T electricity. produces ypical plant size from 300 MW ginal cost of the available generating plants. of Because MW. 1,000 flexibility limited the and size their to centralized that is in herent in the boiler design, these plants generating technologies is subject Construction of different require fairly long start-up times to become operational and to a number of issues, including community concerns, region - produce to flexibility their power are limit ed in output beyond al emission restrictions and the availability of fuels or other a certain range. Furthermore, these plants are generally not resources: necessary as economical or easy to site as some newer technologies – - Wind plants are generally built in areas with the appropri • which explains why few have been built in recent years. ate meteorological conditions. In most cases, these sites are small, quick-start units similar to an Gas turbines (GT) are located in rural areas with limited transmission access. aircraft jet engine. These plants are also called simple cycle For example, in West Texas, the transmission lines con - turbines or combustion turbines (CT). GTs are relatively inex- necting wind farms with consumer centers in Dallas and pensive to build, but are expensive to operate because they overloaded, requiring generators to Houston can become are inefficient, providing low output power relatively the for curtail production. amount of gas burned, and have high maintenance costs. • Coal plants have environmental characteristics that limit They are not designed to run on a continuous basis and are and siting their both emit they Specifically, operations. used to serve the highest demand during peak periods, such NO , particulates, mercury and substantially higher , SO x x - as hot summer afternoons. GTs also run when there are sys plan ts. This has made financing than levels of CO gas-fired 2 tem-wide shortages, such as when a power line or generator urban near difficult. centers siting and plants these them have GT a short operational life due to s trips offline. typically There have been virtually no new nuclear plants built in • the wear-and-tear caused by cycling. The typical capacity of a the United States in the past 30 years. The technology of | C egulatory r nergy e ederal F ommission Energy Primer 48

55 GT is 10-50 MW and they are usually installed in banks of mul - facilities are expensive to run and also emit more pollutants tiple units. than gas plants. These plants are frequently uneconomic and generators, Like factors. capacity low at run typically gas-fired Combined cycle power plants (CCPPs) are a hybrid of the GT there are several types of units that burn oil; primarily, these incor this and steam - boile r technologies . Specifically, design are steam boilers and combustion turbines. - porates a gas-combustion turbine unit along with an associat Generally, ed generator, and a heat recovery steam generator along with generation: power for used are oil of types two highly turbine. power number 2 and number 6 (bunker) fuel oil. Number 2 is a lighter its own steam The result is a efficient plant. They produce negligible amounts of SO and particulate and cleaner fuel. It is more expensive, but because it produces 2 and CO emissions and their NO significantly fewer pollutants when burned, it is better for locations with emissions are x 2 - stringent environmental regulations such as major metropoli lower than a conventional coal plant. CCPPs, on average, re- - tan areas. Conversely, number 6 fuel oil is cheaper, but consid 80 less land than a coal-fired percent plant, typically 100 quire acres for a CCPP versus 500 acres for comparable coal plant, ered dirty because of its higher emissions. It is highly viscous and CCPPs also use modest amounts of water, compared to (thick and heavy) and it comes from the bottom of the barrel other technologies. refining in process. the 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 power flexible especially not - out their lowering or g raisin in fixed low but costs, and high put. Nuclear plants have capital 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 for off-line taken are that At cycle. fuel point, refueling they - and maintenance. Outages typically last from 20 days to sig nificantly longer, depending on the work needed. Renewable Generation Renewable resources use fuels that are not reduced or used Coal plants generate more than one-third of the electricity in up in the process of making electricity. They generally include the United States. These facilities tend to be large, baseload solar, ower, hydrop and - ermal, geoth biomass, onshore off units that run continuously. They have high initial capital costs shore wind, hydrokinetic projects, fuel cells using renewables and are also somewhat complex in their design and opera- and biogas. plants , However tions. have low marginal coal costs and can Renewable generation, an important part of total U.S. capac - substantial amounts of power. of the coal-fired produce Most ity and generation, accounted for 13 percent of 2014 electric - plants in the United States are located in the Southeast and ity generation. As total generation from all fuels has remained Midwest. relatively constant in the recent years, renewable genera- Oil-fired plants generally produce only a small amount of the tion’s share has risen, spurred by state regulations and federal total electricity generated in the U.S. power markets. These tax credits. As renewable generation becomes a larger per - | Energy Primer 49

56 of rock, geothermal gradient, heat centage of generation resources, integrating them into the flow sedimentary and sur - face temperature. Geothermal generation increased 14 per- operating power grid has presented challenges. cent from 2006 to 2014, but it decreased from 15 to 6 percent Wind and solar capacity have grown faster than other renew- of non-hydro renewable output, due to the growth of other able resources in recent years. Wind capacity grew ten-fold renewables. California hosts more than 80 percent of U.S. op - (from approximately 6 GW to 65 GW) between 2003 and 2014. erating capacity. Utility-scale solar capacity more than tripled (from approxi - mately 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 condi tions. But as renewable resources are often weather-depen- dent, their capacity factors – the ratio of average generation period – have the been to capacity for a specific nameplate lower (for example, approximately 30 percent), depending for fossil-fuel-fired generation. on the technolo gy type, than between and Markets care about the difference nameplate capacity factor values when they evaluate capacity available - to cover expected load. Capacity factors have risen with tech nological innovation and improved manufacturing processes. Wind generation is among the fastest-growing renewable re- sources, in part due to cost declines and technology improve- ments as well as earlier receipt of federal tax credits. Increas- es in average hub heights and rotor diameters have increased average wind turbine capacity. transforms sunlight into electricity using Solar generation Because the best wind resources are often far from load cen - phot one two of technologies: ovoltaic (PV) or concentrating sufficient transmission ters, a challenge presents obtaining solar power (CSP). PV modules, or panels, transform sunlight to delivering its output. Other market challenges for future wafers silicon using power into directly or thin-film nonsilicon wind development include its variable output, which is often technologies. They can be installed on roofs of buildings or at - inversely correlated to demand (seasonally and daily); sys ground-level PV farms. CSP plants use a two-step process to tem operators’ inability to dispatch wind resources to meet transform the sun’s energy. First, mirrors direct sunlight to- difficulties forecasting related to load increases; accurately wards a receiver that captures the heat. CSP then employs a its ramping; and the need for companion generation (usually thermal process to create steam, driving an engine or turbine fossil-fueled) to be available to balance wind generation when to produce electricity. CSP plants, which are dispatchable, can the wind is not blowing. include low-cost energy storage that extends their availability Geothermal generation taps into reservoirs of steam and hot later in peak hours. water deep beneath the earth’s surface to produce power. PV growth has increased greatly as a result of policy incentives - The best resources are in the intermountain West. Geother and cost declines. Annual PV installations increased nearly mal potential is determined by thermal conductivity, thickness | C egulatory r nergy e ederal F ommission Energy Primer 50

57 tenfold from 2009 to 2013 as PV system costs decreased. PV be installed at farms anywhere, used to run farm operations - and reduce methane emissions from natural manure decom growth has been relatively concentrated; 10 states had 90 position. percent of PV capacity in 2014, while California alone had over half. Renewable Energy Policies By the end of 2014, 1,760 MW of CSP was operational. Seven western and southwestern states have extensive CSP poten - Renewable development is frequently tied to policies pro- Utah, California and Mexico, tial: New Arizona, Nevada, T exas, moting their use because of their higher cost relative to other Colorado. Developing that potential will require overcoming technologies. Financial incentives include tax credits, low-cost challenges of siting, transmission and the need for extensive loans, rebates or production incentives. Federal funding of re- water supplies to clean mirrors. search and development (R&D) has played an important role in lowering costs or reducing the time it takes for renewable is powered by the kinetic energy Hydroelectric generation technologies to become commercially viable. of falling water that drives turbine generators, which convert - the energy into electricity. There are two types of hydroelec Congress has provided tax incentives to spur renewable re- tric and pumped storage. Conventional projects: conventional source investments. Originally enacted in 1992, wind, biomass, projects, which use a dam in a waterway, can operate in a geothermal, and other forms of renewable generation have mode, in water outflow from the run-of-river project which been able to receive federal production tax credits (PTC) reser - which in mode, the a in or inflow, approximates peaking based a facility’s productio on n. An inflation-adjusted credit, voir is mostly drained to generate power during peak periods the PTC generally has a duration of 10 years from the date the when energy is more valuable. Pumped storage projects use initially set was credit The ine. onl oes g facility at 1.5¢/kilowatt ater of water at two bodies different elevations. W is pumped was 2013 in value its and (kWh) hour 1.1¢/kWh, or 2.3¢/kWh reservoir into elev ated storage when s during off-peak periods depending on the type of qualifying resource. The PTC has pumping energy is cheaper; the water is then used to gener- been renewed and expanded numerous times, most recently during peak periods as it flows back to the lower ate pow er at the end of 2014. elevation reservoir. Pumped storage is significant the only - commercially deployed electricity storage technology avail Another form of tax credit for renewables, including solar and able today. other select renewable energy projects, has been a federal in - vestment tax credit (ITC). The ITC has generally been for 30 Biomass generation includes production from many waste by - percent of a project’s equipment and construction costs. gas, municipal products, such landfill as agricultural residues, solid waste and wood resources. The largest biomass catego - the Reinvest American the 2008, of crisis Following financial - ry is wood waste, burned for heat and power in the lumber, ment and Recovery Act (ARRA) provided developers with pulp and paper industries. Challenges to biomass production another option for projects that began construction by the include impacts on food supplies (for example, converting end of 2010 – they could apply for Treasury-administered cash and corn ethanol), natural into minimiz - conserving resources front. up value C’s IT the funds ARRA grants, which monetized ing water pollution. State policies on renewable generation helped support renewable energy research and development biomass eligibility technologies. on differ of and aided capacity growth in 2009, despite the economic downturn. - Biogas energy is created through the anaerobic (without oxy gen) bacterial decomposition of manure, which is turned into State renewable portfolio standards (RPS) and renewable a gas containing 60-70 percent methane. Biogas recovery can the in energy standards (RES) have been significant drivers | Energy Primer 51

58 residential renewable generation and growth of investment in renewable generation. An RPS re- by projects dium-sized independent commercial developers. quires a certain percentage of energy sales (MWh) to come - from renewable resources. Percentages usually increase in to utilities require FITs at generation renewable the fixed a buy crementally from a base year to an ultimate target. Current- rate that is higher than that provided to other generators, ly, 29 states plus Washington, D.C., have an RPS and eight under multiyear contracts. This enables smaller distributed penalties states h ave renewable goals for financial without renewable generators to avoid having to participate in renew- nonachievement. As utilities build more renewable-powered able portfolio standard (RPS) auctions or other competitive generation, the markets in which they participate continue to procurements and compensates them for more expensive address the integration of renewable output into their day- technologies. The utility passes the costs of the program to ahead and real-time operations and model expected growth its customers. 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 consump - tion, 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 re- newables. Renewable energy certificates regulators state allow (RECs) to track compliance with mandatory RPS targets or verify progress in voluntary state renewable programs. They also al- low compliance entities to purchase credits – subject to state imposed limits on amount and price - if they have not generat - ed or bought enough renewable energy to meet their annual requirements. Each reported megawatt-hour (MWh) of eli- gible generation results in a system-issued REC with a unique identification REC prevent double-counting. to number Each includes attributes such as generator location, capacity, fuel- type and source, owner and the date when operations began. a States and loca l utilities offer variety incentives financial of Transmission for renewable energy to complement policy mandates. These - include tax credits for in-state manufacture of renewable en The alternating current (AC) power grid operates like an in - ergy equipment, consumer rebates for purchase and installa - with where, web, a few exceptions, the flow of terconnected tion of renewable generation or production incentives. Pro- controlled a on operators the line- by power is not specifically duction incentives include extra credits for solar output based of generation power basis. by-line Instead, flows from sources solar on RPS tariffs. set-asides and feed-in to consumers across any number of lines simultaneously, fol - - lowing the path of least resistance. There are a limited num to support their Seven states mandate feed-in-tariffs (FIT s) ber of direct current (D C) lines, specific which are set up as energy and environmental goals. Also called feed-in rates or end points for scheduling beginning definite and paths with advanced renewable incentives, these programs typically are and moving power. These lines are controllable by operators designed to encourage development of new small- and me- | C egulatory r nergy e ederal F ommission Energy Primer 52

59 prices for capacity reassignments, as opposed to the original and have other characteristics that make them attractive to grid planners and operators, such as providing greater grid cost-based price at which they purchased the capacity. The and lower line losses. However, D C lines cost signifi number of capacity reassignments increased from around stability - 350 in 2007 to 30,000 in 2012. Most of the transactions were cantly more than AC lines to construct. Consequently, DC lines built for certain specialized applications involving are typically hourly, although capacity can also be reassigned on a daily, monthly or yearly basis. moving large amounts of power over long distances, such as Intertie, which extends between the Northwest the Pacific If the market price of energy is greater at the POD than at the and California. POR, the transmission has value. The transmission holder can capture this value by using the transmission – buying energy Transmission lines provide a certain amount of resistance to This as electricity travels through them. re - at the POR, moving it to the POD and selling it. Alternatively, flow the of power sistance is not unlike the wind resistance that a car must over- the transmission holder can sell the transmission through a come as it travels along a highway. The resistance in power capacity reassignment. Thus, the price of a capacity reassign - of power injected into a pow - lines creates losses: the amount ment should be equal to the expected price differential be - tween the POD and the POR. er 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. Grid Operations Grid operators dispatch their systems using the least costly Transmission Service generation consistent with the constraints of the transmis - sion system and reliability requirements. The dispatch process FERC requires that public utilities that own transmission lines occurs commitment, unit day-ahead stages: or plan - two a on service transmission offer commerce interstate in used in nondiscriminatory basis to all eligible customers. The rates ning for the next day’s dispatch, and economic dispatch, or and terms of service are published in each utility’s Open Ac- dispatching the system in real time. of service is point- T ransmission T ariff (OA TT). cess One type to-point service. This service involves paying for and reserving Day-Ahead Unit Commitment of power moving a fixed quantity and transmission capacity up to the reservation amount from one location, the point In the unit commitment stage, operators decide which gener- of receipt (POR), to another location, the point of delivery ating units should be committed to be online for each hour, (POD). Depending on availability, customers may purchase typically for the next 24-hour period. This is done in advance of point-to-point service for durations of one hour to multiple real-time operations because some generating units require years. The price for the service is cost-based and published in several hours lead time before they are brought online. In se- the OATT. In cases where there are multiple parties desiring lecting the most economic generators to commit, operators transmission, it is allocated to the party willing to purchase it take into account forecast load requirements and each unit’s for the longest period of time. Capacity reassignment is the physical operating characteristics, such as how quickly output term for the resale of point-to-point transmission capacity in can be changed, maximum and minimum output levels and the secondary market. - the minimum time a generator must run once it is started. Op erators must also take into account generating unit cost fac- - Transmission holders may want to sell capacity in the second tors, such as fuel and nonfuel operating costs and the cost of use it is unneed - or to make Capac ary market a profit. beca ed, environmental compliance. ity reassignment has been permitted since 1996. Beginning in 2007, resellers have been permitted to charge market-based | Energy Primer 53

60 conditions that can forecast affect the transmission Also, generation and interchange (imports and exports) must be in hertz. 60 of frequency system a maintain to balance kept grid must be taken into account to ensure that the optimal This is typically done by automatic generation control (AGC) dispatch can meet load reliably. This is the security aspect of that to change the generation dispatch as needed. commitment an alysis. Factors can affect grid capabilities include generation and transmission facility outages, line ca - The chart below is a depiction of the market supply curve of loading levels and flow direction and as affected by pacities the power plants for the New York Independent System Op - weather conditions. If the security analysis indicates that the erator (NYISO). This is also commonly called the supply stack. - optimal economic dispatch cannot be carried out reliably, rela In it, all of the plants in the New York market are shown sorted - tively expensive generators may have to replace less-expen according to their marginal cost of production. Their cost of sive units. production is shown on the vertical axis. The cheapest ones to run are to the left and the most expensive to the right. System and Unit Dispatch example, wind plants, Dispatch in New Y ork, for first calls on In the system dispatch stage, operators must decide in real followed successively by hydro, nuclear and coal-, gas- and oil- time the level at which each available resource from the unit assumes fired generators. This that the plants have sufficient commitment stage should be operated, given the actual load resources – enough wind for the wind powered generators and grid conditions, so that overall production costs are mini - for plants, hydroelectric the for flow river gh enou example or forecast Actual conditions will vary mized. from those the in that deliver sufficient to exists capability and transmission – day-ahead commitment, and operators must adjust the dis- plant output and meet reliability needs. patch accordingly. As part of real-time operations, demand, Market Supply Curve for NYISO (Illustrative) | C egulatory r nergy ommission ederal F e Energy Primer 54

61 transmission flows must be monitored to ensure addition, In can also be provided by demand-side resources. flows stay within voltage and reliability limits. If transmis - that come from generating units that • Supplemental reserves the operator must take limits, accepted sion flows exceed can be made available in 30 minutes and are not neces- corrective action, which could involve curtailing schedules, Supple - sarily synchron ized frequency. system with the changing the dispatch or shedding load. Operators may check mental reserves are usually scheduled in the day-ahead conditions and issue adjusted dispatch instructions as often as offer market, energy reserve their to generators g allowin every five minutes. at a price, thus compensating cleared supply at a single to applies only This price. clearing market and ISO/RTOs, Ancillary Services not all reliability regions have a supplemental reserve re - quirement. Ancillary services maintain electric reliability and support the transmission of electricity. These services are produced and - generating units have the ability to go from a shut Black start consumed in real-time, or in the very near term. NERC and re- down condition to an operating condition and start delivering - gional entities establish the minimum amount of each ancil power without any outside assistance from the electric grid. lary service that is required for maintaining grid reliability. diesel and facilities Hydroelectric this capabil generators - have matches generation with very short-term changes Regulation started be to facilities first e th are These ity. in of event the up in load by moving the output of selected resources up and a system collapse or blackout to restore the rest of the grid. down via an automatic control signal, typically every few sec- onds. 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 genera line. off trips unit generating a when balance tion Operating reserves are provided by generating units and demand re- sources that can act quickly, by increasing output or reducing deficiency. demand, to make up a generation There are three types: • Spinning reserves are primary. To provide spinning re - generat or must be on line (synchronized to the serve a system frequency) with some unloaded (spare) capacity and be capable of increasing its electricity output within 10 minutes. During normal operation these reserves are consists of current, the : flow of Reactive power Electricity provided by increasing output on electrically synchro - electrons, and voltage, the force that pushes the current reducing load on pumped storage equipment or nized by through the wire. Reactive power is the portion of power that reserve be also can nized Synchro facilities. hydroelectric in fields magnetic and AC establishes and maintains electric provided by demand-side resources. equipment. It is necessary for transporting AC power over transmission lines, and for operating magnetic equipment, in - come from generating units that • Nonspinning reserves cluding rotating machinery and transformers. It is consumed can be brought online in 10 minutes. Nonspinning reserve | Energy Primer 55

62 current flowing electricity of amount by on as it flows. As the Wholesale Electricity Markets and a line increases, so does the amount of reactive power need- Trading ed 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 Overview transmission grid is also capable of injecting reactive power to maintain voltage. Markets for delivering power to consumers in the United split are States two systems: traditional into regulated mar - Weather kets and market-regulated markets run by RTOs. - In general, RTOs use their markets to make operational deci Weather is the single greatest driver of electricity demand sions, such as generator dispatch. Traditional systems rely on - and, thus, is a major factor in grid operations. System opera management to make those decisions, usually based on the tors therefore rely heavily on weather forecasts to ensure cost of using the various generation options. they have the right generation in the right locations to run the grid reliably. Trading for power is also split into over-the-counter (OTC) or bilateral transactions, and RTO transactions. Bilateral transac - Pri - Weather affect s grid operations in other ways, as well. tions occur in both traditional systems and in RTO regions, but mary among these is on the productivity of certain types of ways. in different ors: wind and generat power turbines’ Wind hydroelectric. power output changes with wind availability and speed, which Pricing in both RTO and traditional regions incorporate both affects cost of wholesale power. cost-of-service and market-based rates. on rain and snowfall to provide the Hydroelectric plants rely Bilateral Transactions is river flow needed most this Geographically, output. their for important hydro Pacific Northwest, where seasonal the in Bilateral or OTC transactions between two parties do not oc - plant output is a critical source of power. Rain and the melt- cur through an RTO. In bilateral transactions, buyers and sell - ing of winter snowpack feed the Columbia and Snake river ers know the identity of the party with whom they are doing systems. Surplus power from these generators is typically business. exported to California to help meet summer peak demand and provide a combination of increased reliability and lower - Bilateral deals can occur through direct contact and negotia prices. tion, through a voice broker or through an electronic broker - age platform, such as the IntercontinentalExchange (ICE). The Temperature plants ca n also affect the output of other power deals as such packages, contract standardized from range can thermal Specifically, es. lin plants transmission of acity cap and to known traded on ICE, those customized, complex contracts that use a turbine – coal, gas, oil and nuclear plants – become as structured transactions. temperatures. efficient at higher less Additionally, the capac - - ity of transmission lines is limited by heat because the conduc Whether the trade is done on ICE, directly between parties or tive material used in fabrication becomes more electrically re- through another type of broker, the trading of standard physi - sistant as they heat up, limiting their throughput. suc products, h as next-day on-peak firm cal and financia l or swaps, allows index providers to survey traders and publish price indexes. These indexes provide price transparency. | C egulatory r nergy ommission ederal F e Energy Primer 56

63 Physical bilateral trades involving the movement of the ener and plants distribution office and related administration - gy from one point to another require that the parties reserve facilities. - transmission capacity to move the power over the transmis • Determining expenses from the production, transmission - sion grid. Transmitting utilities are required to post the avail - and distribution of electricity, including fuel and pur chased power, taxes and administrative expenses. offer service on an ability transmission capacity Open and of Establishing a fair return on capital, known as the cost Access Same-Time Information System (OASIS) website. • of capital. This includes determining the cost of debt, Traders usually reserve transmission capacity on OASIS at the same time they arrange the power contract. common equity, preferred stock and commercial paper and other forms of short-term borrowing such as lines of When it comes time to use the reservation to transfer power projects finance to used credit day- for cash provide and between balancing authorities, one of the parties to the trans - to-day operations. action submits an eTag electronically to Open Access Tech - Allocating electric plant and other expenses among vari - • nology International (OATI), NERC’s eTag contractor. OATI ous customer classes and setting the rate structure and will process the tag and send it to all parties named on the rate levels. eTag. This ensures the orderly transfer of energy and provides transmission system operators the information they need to Market-Based Rates institute curtailments as needed. Curtailments may be needed when a change in system conditions reduces the capability of Under market-based rates, the terms of an electric trans - the transmission system to move power and requires some action are negotiated by the sellers and buyers in bilateral transactions to be cut or reduced. markets or through RTO market operations. The Commis - sion grants market-based rate authority to electricity sellers Bilateral physical transactions conducted in RTOs are settled affiliates their and have or lack that demonstra te that they financially. - mar RTO the into power their offer Generators of (percent power market tal horizon igated mit adequately kets, and load is served through the power dispatched by the generation owned relative to total generation available in a RTO. The RTO then settles bilateral transactions based on the market), and vertical market power (the ability to erect bar - prices in the contracts and the prices that occurred in the RTO competi influence riers to entry or - the cost of production for markets. tive electricity suppliers). Wholesale sellers who have market- based rate authority and who sell into day-ahead or real-time Cost-Based Rates to subject so do RTO a by administered markets specific the RTO market rules approved by the Commission and applicable Cost-based rates are used to price most transmission services to all market participants. Thus, a seller in such markets not and some electricity when the Commission determines that of analysis on based authorization - an in have that must only market-based rates are not appropriate, or when an entity dividual seller’s market power, but it must abide by additional does not seek market-based rate authority. Cost-based rates RTO tariff. rules in the contained are set to recover costs associated with providing service and - give a fair return on capital. Cost-based rates are typically list Supplying Load published in a ed tariff. The following are major inputs to setting cost-based electric- Suppliers serve customer load through a combination of self- ity rates: supply, bilateral market purchases and spot purchases. In ad- dition to serving load themselves, load-serving entities (LSEs) • Determining used-and-useful electricity plants. This The choices are: can contract with others to do so. may include generation facilities, transmission facilities, | Energy Primer 57

64 nessee Valley Authority and the Western Area Power Admin - Self-supply means that the supplying company generates • istration. Wholesale physical power trading typically occurs power from plants it owns to meet demand. • through bilateral transactions. Utilities in traditional regions - Supply from bilateral purchases means that the load-serv responsibilities: have following the ing entity buys power from a supplier. • Supply from spot RTO market purchases means the sup - • Generating or obtaining the power needed to serve cus - plying company purchases power from the RTO. tomers (this varies by state) • Ensuring the reliability of its transmission grid Balancing supply and demand instantaneously • • Dispatching its system resources as economically as pos - sible • 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 markets run by regional electricity transmission organizations Source: PJM Interconnection or independent system operators (this primer uses RTO to LSEs’ sources of energy vary considerably. In ISO-NE, NYISO stand for both RTOs and ISOs). The main distinction between and CAISO, the load-serving entities divested much or all of RTO markets and their predecessors (such as vertically inte- their generation. In these circumstances, LSEs supply their grated utilities, municipal utilities and co-ops) is that RTO mar- customers’ requirements through bilateral and RTO market kets deliver reliable electricity through competitive market purchases. In PJM, MISO and SPP, load-serving entities may mechanisms. either amounts of generation significant directly or own an following: basic functions of RTO include the The therefore and s affiliate - through bi as well as self-supply use lateral and RTO market purchases. Ensure the reliability of the transmission grid • the grid in a Operate defined geographic footprint • • Balance supply and demand instantaneously Traditional Wholesale Electricity Markets - • Operate competitive nondiscriminatory electricity mar kets Traditional wholesale electricity markets exist primarily in Provide nondiscriminatory interconnection service to • the Southeast, Southwest and Northwest where utilities are generators responsible for system operations and management, and, Plan for transmission expansion on a regional basis • typically, for providing power to retail consumers. Utilities in these markets are frequently vertically integrated – they own In performing these functions, RTOs have operational control the generation, transmission and distribution systems used to of the transmission system, are independent of their mem- serve electricity consumers. They may also include federal sys- bers, transparently manage transmission congestion, coordi- tems, such as the Bonneville Power Administration, the Ten- nate the maintenance of generation and transmission system, | C egulatory r nergy ommission ederal F e Energy Primer 58

65 any - - differences between the and oversee a transmission planning process to identify need schedule in the day-ahead mar ed upgrades in both the near- and long-term. ket and the real-time load while observing reliability criteria, electricity forced or unpla nned outages and the flow on limits RTOs do not own transmission or generation assets perform transmission lines. the actual maintenance on generation or transmission equip - ment, or directly serve end use customers. energy day-ahead The binding financially produces market schedules for the production and consumption of electricity Currently, seven RTOs operate in the United States, listed be- one day before its production and use (the operating day). low in order of load: peak their of size the The purpose of the day-ahead market is to give generators • PJM Interconnection (PJM), 165 GW (summer of 2011) - and load-serving entities a means for scheduling their activi • Midcontinent ISO (MISO), 126 GW (summer of 2011) ciently prior forecast a on based operations, their to suffi ties Electric Reliability Council of Texas (ERCOT), 68 GW (sum - • of their needs and consistent with their business strategies. mer of 2011) In day-ahead markets, the schedules for supply and usage of • California ISO (CAISO), 50 GW (summer of 2006) - energy are compiled hours ahead of the beginning of the op Southwest Power Pool (SPP), 48 GW (summer of 2011) • The day. erating model market computerized a runs then RTO New York ISO (NYISO), 34 GW (summer of 2013) • that matches buyers and sellers throughout the geographic New England ISO (ISO-NE), 28 GW (summer of 2006) • - market footprint for each hour throughout the day. The mod based participants, the of and bids the evaluates then el offers to on - through electricity the move needed flows power the RTO Markets and Features out the grid from generators to consumers. Additionally, the model must account for changing system capabilities that RTO market operations encompass multiple services that are occur based on weather and equipment outages, plus rules efficient electric economically and reliable provide to needed and procedures that are used to ensure system reliability. The service to customers. Each of these services has its own pa- market dictate that submit supply rules offers and generators rameters and pricing. The RTOs use markets to determine the loads submit demand bids to the RTO by a deadline that is typ - - provider(s) and prices for many of these services. These mar ically in the morning of the day-ahead scheduling. Typically, 95 kets include the day-ahead energy market (sometimes called percent of all energy transactions are scheduled in the day- a Day 2 market), real-time energy market (sometimes called ahead market, and the rest scheduled in real-time. a Day 1 or balancing market), capacity markets (designed to ensure enough generation is available to reliably meet peak Generation and demand bids that are scheduled by the day- ancillary trans - financial markets, power s), demand services ahead market are settled at the day-ahead market prices. In- - mission rights (contracts for hedging the cost of limited trans day-ahead a setting into puts include: schedule market capability) and virtual trading (financial instruments mission hour • Generator offers to sell electricity each to create price convergence in the day-ahead and real-time Bids to buy electricity for each hour submitted by load- • markets). serving utilities customers Demand-response offers by • to curtail usage of RTO Energy Markets electricity and offers bids demand supply • Virtual - All RTO electricity markets have day-ahead and real-time mar Operational information about the transmission grid and • kets. The day-ahead market schedules electricity production generating resources, including planned or known trans - and consumption before the operating day, whereas the re- mission and generator outage, the physical characteristics al-time market (also called the balancing market) reconciles | Energy Primer 59

66 the the marginal - loca specific at of generating resources including minimum and maximum load serving of cost reflects tion, given the set of generators that are dispatched and the output levels and minimum run time and the status of limitations of the transmission system. LMP has three ele- interconnections to external markets and charge congestion a ments: charge charge, energy an a The real-time market is used to balance the differences be - for transmission system energy losses. tween the day-ahead scheduled amounts of electricity based on day-ahead forecast and the actual real-time load. The real- If there are no transmission constraints, or congestion, LMPs time market is run hourly and in 5-minute intervals and clears - vary ransmis T will significantly not across the RTO footprint. a much smaller volume of energy and ancillary services than sion congestion occurs when there is not enough transmission the day-ahead market, typically accounting for only 5 percent capacity for all of the least-cost generators to be selected. The of scheduled energy. For generators, the real-time market - result is that some more expensive generation must be dis into the ies opportunit nal additio provides for offering energy patched to meet demand, units that might not otherwise run market. Megawatts over- or under- produced relative to the if more transmission capacity were available. day-ahead commitments are settled at real-time prices. Source: ISO New England Source: ISO New England When there are transmission constraints, the highest variable than volatile more significantly are prices market Real-time cost unit that must be dispatched to meet load within trans - - the day-ahead market prices. This stems from demand uncer mission-constrained boundaries will set the LMP in that area. tainty, transmission and generator forced outages and other All sellers receive the LMP for their location and all buyers pay unforeseen events. Because the day-ahead market generally the market clearing price for their location. is not presented with these events, it produces more stable prices than in real-time. Also, because the volumes in the real- The primary means used for relieving transmission congestion time market are much smaller, there is an increased likelihood constraints - is by changing the output of generation at differ of supply and demand imbalances, which lead to both positive ent locations on the grid. The market-based LMP sends price and negative price movements. signals that refl ect congestion costs to market participants. account both the impact specific LMPs take into That is, of RTOs use markets to deal with transmission constraints generators on the constrained facility and the cost to change through locational marginal pricing (LMP). The RTO markets (redispatch) the generation output to serve load. This change calculate a LMP at each location on the power grid. The LMP | C egulatory r nergy e ederal F ommission Energy Primer 60

67 Establish a pricing structure for operating reserves that • in dispatch is known as security constrained redispatch. - would raise prices as operating reserves grow short (de This redispatch could be implemented by using nonmarket mand curve) procedures such as transmission loading relief (TLR). NERC Set the market-clearing price during an emergency for all • established the TLR process for dealing with reliability con - supply and demand response resources dispatched equal cerns when the transmission network becomes overloaded to the payment made to participants in an emergency protect the network. A and power flows must be reduced to demand-response program TLR is used to ration transmission capacity when the demand Reliability must-run (RMR) units are generating plants that - for transmission is greater than the available transmission ca would otherwise retire but the RTO has determined they are pacity (ATC). The rationing is a priority system that cuts power needed to ensure reliability. They could also be units that have based on size, contractual terms and scheduling. flows market power due to their location on the grid. RTOs enter into cost-based contracts with these generating units and al - locate 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 maintain - and owning of cost must be sufficie nt to pay for th e ing 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 ad- Source: PJM Interconnection ion generat equate - genera sufficient that ensure to reserves - Scarcity pricing is a mechanism used by RTOs to send price sig tion and demand-resource capacity are available to meet load - nals in the real-time market when there is a systemwide short quirements. re their satisfied reliability and have typically LSEs age of power reserves. These events occur when there is a reserve obligations with owned generation or bilateral con - shortage of power to meet system requirements to meet load tracts with other suppliers. Some RTOs have mechanisms to and by caused be can This provide reserves. backup cient suffi obtain capacity commitments, such as capacity auctions and unexpectedly high power loads, supply disruptions or both. capacity payments. RTOs follow one of four approaches to ensure that the market - Most RTOs run a capacity market to allow LSEs a way to sat value of energy during price for energy accurately reflects the isfy their reserve obligation. These markets cover short-term periods: shortage capacity, such as a month, season or year. PJM and ISO-NE run capacity auctions up to three years prior to when the capac - Increase the allowed bidding price of energy supply above • ity is needed. The near-term focus is consistent with providing normal levels during an emergency - payments to existing generation, or generation such as com - Increase bid caps above the current level during an emer • bustion turbines that can be sited and built within three years. for demand bids, while keeping generation offer gency caps in place | Energy Primer 61

68 be converted to FTRs. As with FTRs, ARRs, too, give eligible Financial Transmission Rights congestion transmission against hedge or members an offset costs in the day-ahead market. If converted to FTRs, the hold- Financial transmission rights (FTRs) are contracts that give er gets revenue from congestion. If kept as ARRs, the holder transmission against hedge, or offset, ants market particip an gets revenue from the FTR auction. congestion costs in the day-ahead market. They protect the holder from costs arising from transmission congestion over a The main method for procuring FTRs is through an auction, path grid. on specific the which typically includes an annual (or multiyear) auction of one-year FTRs and monthly (or semiannually) auctions of FTRs were originally developed in part to give native load- shorter-term FTRs provided by existing FTR holders or made serving entities in the nascent RTOs price certainty similar to available by the RTO. The auctions are scheduled and run by - that available to traditional vertically integrated utilities op the RTO, which requires bidding parties to post credit to cover erating in non-RTO markets. This practice continues, as FTRs the positions taken. FTR auction revenues are used to pay the are allocated to load-serving entities, transmission owners or holders of ARRs and assist the funding of future congestion based RTOs in historical holders right transmission firm on payments to FTR holders. There is also a secondary market for fun d usage, the construction of specific and to entities that FTRs (such as PJM’s eFTR), but only a small number of transac - new transmission facilities. The details of the programs vary tions have been reported. by RTO. - FTRs allow customers to protect against the risk of conges tion-driven price increases in the day-ahead market in the RTOs. Congestion costs occur as the demand for scheduled that power over a transmission flow path’s exceeds path 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 the congestion prices at paid is holder the difference of the - sink and source, thus allowing it to hedge against the conges tion costs incurred in the day-ahead market. The quantity of FTRs made available by the RTO is bounded FTRs are acquired through allocations and purchases. FTRs - by the physical limits of the grid, as determined by a simul can be purchased in the RTO-administered auctions or in the potential all test feasibility taneous across This flowgates. secondary market. test is performed by the RTO prior to making FTRs available at auction, and takes into account existing FTR positions and Allocations may stem from a related product, the auction system constraints. The resulting portfolio of FTRs allocated right (ARR). ARRs - ca provide the firm transmission revenue or the offered at au ction represents an absolute constraint on pacity holders, transmission owners or LSEs with a portion of - size of the net positions that can be held by the market. Par the money raised in the FTR auctions. In general, they are al- counterflow procure can auctions FTR in which FTRs, ticipants located based on historic load served and, in some RTOs, can | C egulatory r nergy e ederal F ommission Energy Primer 62

69 offer flow FTR capacity, thereby allowing directly offset products. off-peak and on-peak prevailing the value at risk on a given path to exceed the physical limits RTOs The : allocate transmiss ion rights to Allocated Rights the line. However, such bids constrained, as of are physically transmission owners or load-serving entities within their mar- the net position held on the path must always conform to the kets. In PJM, MISO, SPP, and ISO-NE, these are allocated as simultaneous feasibility test. auction revenue rights (ARRs), which give their holders the - right to receive a share of the funds raised during the FTR auc Although FTRs are used by transmission providers and load- tions. The CAISO allocates congestion revenue rights (CRR), serving entities as a hedge, they can be purchased by any as either which provide their holders a stream of payments based on financial their seeking entity creditworthy attributes the actual congestion occurring on associated paths. Finally, a hedge or as a speculative investment. In this regard, FTRs a contract financial NYISO allocates both auction-based and congestion-based are executed swaps to that similar are as differences between two day-ahead LMPs (swaps for are ex - rights through multiple instruments. PJM and MISO allow ARR However, markets). financial on FTRs chapter the in plained holders to convert all of these rights to FTRs; NYISO allows only a portion of ARR-equivalent instruments to be converted different from swaps in that the quantity are substantially to its version of FTRs, called Transmission Congestion Cred - of FTRs is linked to physical constraints in the transmission its (TCCs). ISO-NE does not allow such conversions, while the grid, while the quantity of swaps is not. Further, FTRs are pro - CAISO’s allocation is already in a form equivalent to an FTR. cured by allocation or FTR auction, while swaps are procured - Converted ARRs are fully fungible in PJM, the MISO and NYI over-the-counter markets or exchanges. through financial - SO; CAISO only allows the sale of allocated CRRs in its second ary market, and ISO-NE has no converted instruments to sell. Variation in RTO FTRs Auctioned Rights (or FTRs provide RTOs All : CRRs, equivalent All six FERC-jurisdictional RTOs trade FTRs or FTR equivalent or TCCs) for sale to the public through two or more auctions trad rights the of qualities and types the However, products. - held at various times of the year. The products sold vary by the ed the across in differences do as vary, markets organized market and by auction, with some products made available methods used to allocate, auction and transfer these rights. auctions. at only specific These attributes of the FTR markets are discussed below. : With the exception Secondary Markets the NYISO, of each of Counterflow. A prevailing flow Flow Type : Prevailing Flow and the markets that auction FTRs also operates a bulletin board - FTR generally has a source in an historic generation-rich loca - or similar venue designed to enable a secondary trading plat tion and a sink that is in a historic load-heavy location. Alter- platforms none of these FTRs. has had for form However, natively, uncon the on is FTR flow prevailing a of urce so the - a bulletin significant board volume. NYISO offered to create strained side of a transmission interface and the sink on the for its participants if requested, but received no requests. The constrained prevailing for prices clearing Auction side. flow CAISO is the only market that requires the reporting of sec- has a FTR FTRs are positive. Conversely, a counterflow often ondary FTR transactions; such transactions have not occurred source in an historic load-heavy location and a sink in an histor - despite the inability of CRR holders to resell their positions ic generation-rich location. As a result, auction clearing prices through the auction process. for negative. counterflow FTRs are Peak Type : purchased be can FTRs 24-hour. Off-peak, On-peak, Virtual Transactions either 16-hour on-peak for 8-hour off-peak blocks or blocks, P Only around-the-clock. - type peak three prod all offers JM Virtual bids and offers (collectively, virtuals) are used by trad - only the 24-hour product. The other RTOs - differ from ucts. NYISO offers ers participatin g in the RTO markets to profit | Energy Primer 63

70 through some Virtuals markets. the - on impact financial their ences between day-ahead and real-time prices. The quantity - times are referred to as convergence bidding, as a competi of megawatts (MW) purchased or sold by the trader in the by of an purchase or sale a offset exactly is market day-ahead tive virtual market should theoretically cause the day-ahead net effect identical quanti ty of MW in the real-time, so that and real time prices to converge in each hour. the traded zero. is on the quantity market The convergence of day-ahead and real-time prices within the RTOs is intended to mitigate market power and improve the Although a trader does not have to deliver power, the transac - a have virtuals load. ving ser of efficiency Thus, tion is not strictly financial. Virtual transactions can physically impact physical upon the operations of the RTO, as well as on market partici - set the LMPs, the basis for payments to generators or from pants that physically transact at the LMPs set in the day-ahead load. and real-time markets. For each hour, net virtual trades are added to the demand forecast for load if virtual demand is greater than virtual sup - Transmission Operations the ply. This has the effect of raising day-ahead the in price - market and, more importantly, increasing the amount of gen specifies Access Open ransmission T ariff (OA TT) T RTO’s Each eration resources procured by the RTO. Since these resources - the transmission services that are available to eligible cus will be available to the real-time market, the fact that virtual tomers. Customers submit requests for transmission service load does not carry forward into the real-time market will through the Open Access Same-Time Information System decrease the real-time demand below forecast, thus placing (OASIS). RTOs evaluate each transmission-service request us- downward pressure on real-time prices. The placement of vir- ing a model of the grid called a state estimator. Based on the physical capacity. dispatch the affects tuals of request the system, the on effects the model’s estimation of for transmission service is either approved or denied. virtual primary benefits of The transactions are achieved Transmission Rights by Transmission Grid SPP CAISO PJM MISO ISO-NE NYISO Name for Allocated Transmission Rights ARR ARR Multiple CRR ARR ARR - Congestion Rights? Convertible Yes No Some to Yes Yes Name for Auctioned Congestion Rights FTR FTR FTR TCC CRR TCR Congestion Right Auction Format: Annual Yes Yes No Yes 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 Yes Yes Yes Annual No Yes No Semiannual No No Yes No No No Quarterly Yes Yes No No Yes Yes Monthly Yes Yes Yes Yes Yes Yes Auction Allows Yes Participant Resale? Yes Yes Yes Yes No No No Congestion Right Options Yes No No No Market? FTR Secondary Formal Yes Yes No Yes Yes Yes | C egulatory r nergy ommission ederal F e Energy Primer 64

71 mended plan for the entire RTO footprint. major RTOs, offer two types including operators, Transmission service: point-to-point service and network of transmission service. Network service generally has priority over point-to- Financial Policies point service. RTOs work with transmission owners to plan and coordinate the operation, maintenance and expansion of Financial settlements is the process through which payments transmission facilities in order to provide network and point- due from customers and to generators are calculated. Such to-point customers with transmission service. settlements depend on day-ahead schedules, real-time meter- - ing, interchange schedules, internal energy schedules, ancil Network transmission service is used for the transmission of lary service obligations, transmission reservations, energy energy from network generating resources to an RTO’s net- prices, FTR positions and capacity positions. For each market work loads. participant a customer invoice of charges and credits includes • Network transmission service enables network customers the costs of services used to serve load. to use their generation resources to serve their network - Generally, customers receive weekly or monthly invoices stat loads in a RTO. ing their charges and credits. Weekly invoices must be settled • Network customers also can use the service to deliver within a few days of being issued, while monthly invoices economy energy purchases to their network loads. must be paid within either one or two weeks depending on uses an RTO’s system for Point-to-point transmission service the policies of each RTO. All payments are made electroni - the transmission of energy between a point of receipt and a cally. Disbursements are made within several days of the date point of delivery, which can be into, out of, or through the payments are due. Area. RTOs offer firm and nonfirm point-to- RTO’s Control point transmission service for various lengths of time. nonfirm over priority reservation point- has service Firm • to-point service. Credit Policies service is provided • Nonfirm point-to-point transmission - from the available transmission capability beyond net requirements electricity organized in important are Credit point-to-point and firm work service. transmission markets in which RTOs must balance the need for market li - quidity against corresponding risk of default. Defaults by mar - Transmission Planning ket participants in RTOs have generally been socialized, mean - o T market. the across this minimize ing that the cost is spread RTOs have systemwide or regional planning processes that risk, contain which tariffs, their in policies credit have s RTO identify transmission system additions and improvements provisions related to credit evaluations, credit limits, forms of conducted are Studies flowing. that electricity keep to needed collateral and the consequences of violations or defaults. test the transmission system against mandatory national reli- ability standards as well as regional reliability standards. RTO transmission planning studies may look 10-15 years into - the future to identify transmission overloads, voltage limita tions and other reliability problems. RTOs then develop trans- mission plans in collaboration with transmission owners to resolve potential problems that could otherwise lead to over- - loads and blackouts. This process culminates in one recom | Energy Primer 65

72 r Egions 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. would ating facility, it be cost-effective to have reserve shar - Southeast Wholesale Market Region ing agreements with neighboring systems that provided the backup or capacity reserves, rather than building reserves in - The Southeast electricity market is a bilateral market that in - dividually. In addition, a stronger grid allowed the output of cludes all or parts of Florida, Georgia, Alabama, Mississippi, large power plants to be deliverable throughout the region, North Carolina, South Carolina, Missouri and Tennessee. It thus allowing more than one utility to share in the ownership Reli - NERC regions: two of part or all encompasses the Florida and the costs of building large new plants. This reduced the - ability Coordinating Council (FRCC) and the Southeastern Elec risks financial associated - gener new large of ownership with tric Reliability Council (SERC). Major hubs include Into South - ating facilities to any single utility, thus making ownership of ern and TVA. coal and nuclear units more affordable large to the base-load utilities and less risky. Southeastern power markets have their roots in the 1960s. In the wake of the Northeast Blackout of 1967, the Southeast A stronger transmission system also allowed for more eco - began to build out its electric transmission grid; there now are nomic transactions, including both spot transactions and long- several large transmission lines connecting large power plants term - ef more in resulted sales Ext deliveries. power ernal firm to the grid. This was primarily to ensure reliability, but it also ficient of grid resources and buyers use reduced costs to both had economic consequences. Increased integration allowed and sellers. share effectively more to utilities costs the as well as reserves, and risks of new plant construction. Resources Within the Southeast, the resource mix varies between the a utility coal-fired or nuclear large gener building were - a If | C r nergy e egulatory ederal F ommission Energy Primer 66

73 percent of this subregion’s output is from baseload coal and two NERC subregions. The FRCC uses more natural gas- and generation than the rest of oil-fired the Southeast, and it is nuclear facilities. only Southeast area where oil is significantly employed. the Trading and Market Features Natural gas is the marginal fuel in almost all hours in the FRCC. Within SERC, the Southern subregion has historically generat- are Physical and financial using traded products electricity ed as much as 85 percent of its electricity from baseload coal Into Southern, TVA, VACAR and Florida price points. Volumes and nuclear plants. In recent years, natural gas used for gener- for these products remain low, especially in Florida, where ating electricity has become increasingly popular. The pattern merchant power plant development is restricted by a state began to change as gas supplies increased and prices fell and statute. displace plants began to natural older, less- gas-fired power - Virtually all the physical sales in the Southeast are done bi generation. coal-fired efficient - laterally. Long-term energy transactions appear to be a hall The TVA sub-region has a majority of its capacity and output mark of the Southeast; wholesale electricity transactions for - in coal and nuclear, while the VACAR sub-region has the high a year or more outweigh spot transactions. Many long-term of utilization Southeast. est Over 70 the in generation nuclear agreements involve full-requirements contracts or long-term Southeast Electric Region elocity Suite, ABB Source: V | Energy Primer 67

74 to evalu are energy purchase to - bids and energy sell Offers purchase power agreements. Spot transactions accounted ated simple the ng usi for less than one percent of overall supply and tend to occur method of sorting offers in ascending order and bids in descending order. during periods of system stress, usually summer heat waves - or winter cold snaps. Even for a large company such as South The auction matches parties to facilitate a bilateral transaction ern Co., spot transactions occurred less than 20 percent of the that is ultimately independent of the auction. Thus, there is time. - no collateral requirement necessary to participate in the auc credit However, rules dictate that matches are Wholesale spot power markets in the Southeast have relative- screening tion. made only between entities willing and able to do business ly little spot trading and lack transparency. The relative lack with one another. The selection process is based on informa of spot trades yields little data on which to base price report - - tion that each entity submits to the auction administrator. ing. ICE reports no electric power price for Florida. And while another publisher reports one spot electric power price for When the auction began in 2009, Southern Co. was the only Florida, on most days, there are no reported volumes. Given participant that could sell into it. On Jan. 3, 2010, other entities the bilateral nature of wholesale power transactions in the were allowed to sell into the auction, and Southern became the and Southeast, interest market, in financial spot small sales. as well as e eligible in th purchases make to - How auction power products in the Southeast is weak. As a result, ICE does ever, activity in the auction has been sparse since its inception. product provide a financial not in Southeast. the Florida IPP rule Despite the bilateral nature of the wholesale trade and the the marketers market, spot - of size small pres some have do The Florida Public Service Commission’s (PSC) competitive ence in the Southeast. For example, marketers contribute to bidding rules require investor-owned utilities (IOUs) to issue the trading, as they have entered into multiyear agreements requests for proposals for any new generating project of 75 with generating units. MW or greater, exclusive of single-cycle combustion-turbines. The bidding requirement can be waived by the PSC if the IOU Southern Co. Auction can demonstrate that it is not in the best interests of its rate- payers. Since April 23, 2009, Southern Co. has been holding daily and hourly auctions for power within its balancing area. This bal - ancing area encompasses the service territories of Southern Pow Mississippi Power, Alabama Power, - rgia Geo ies: utilit Co. Western Wholesale Market Regions er and Gulf Power. - The power markets in the western United States are primar rules, Southern must offer all According its to the auction of ily bilateral markets. A key exception is most of California available excess generation capacity into the auction, after and portions of Nevada, which operate under CAISO. The The regulation prices and contingency offer reserves are met. West includes the Northwest Power Pool (NWPP), the Rocky are capped because the auction is intended to mitigate any New Arizona, the and A) Mexico, Mountain Power Area (RMP - potential ability of Southern to withhold its generation re Southern within (AZ/NM/SNV) Area Power - est W the Nevada sources within its balancing area. ern Electricity Coordinating Council (WECC), a regional entity. These areas contain many balancing authorities (BAs) respon - The products auctioned are day-ahead power and real-time sible for dispatching generation, procuring power, operating power (an auction takes place an hour ahead of when the en - the transmission grid reliably and maintaining adequate re- to scheduled is ergy flow). serves. Although the BAs operate autonomously, some have joint transmission-planning and reserve-sharing agreements. | C egulatory r nergy ommission ederal F e Energy Primer 68

75 Northwest Electric Region Source: Velocity Suite, ABB There are 80 GW of generation capacity, including 43 GW of Trading in the western states differs from the rest of the coun - try are because financial players hydroelectric generation. active in the physical markets, financial as having a robust as electricity market. The vol - well Resources of financial sales on ICE is roughly as large as physical ume dominated sales in WECC are by financial and sales. Physical is generation Hydro mix. NWPP resource The has a unique marketing companies. more than 50 percent of power supply, compared to the U.S. - average of only 6 percent of power supply. The hydro gen Northwest Electric Region eration is centered around many dams, mostly on or feeding the Columbia River. The largest dam, the Grand Coulee, can The NWPP is composed of all or major portions of the states produce as much power as six nuclear plants. Due to the large of Washington, Oregon, Idaho, Wyoming, Montana, Nevada amount of hydroelectric generation, the Northwest typically and Utah, a small portion of Northern California and the Ca- - has less expensive power and exports power to neighbor nadian provinces of British Columbia and Alberta. This vast ing regions, especially California, to the extent that there is area covers 1.2 million square miles. It is made up of 20 BAs. transmission capacity to carry the power to more expensive The peak demand is 54.5 GW in summer and 63 GW in winter. markets. | Energy Primer 69

76 The largest seller of wholesale power is the Bonneville Power The amount of hydropower produced depends on a number Administration (BPA), a federal agency that markets the out- of factors, some natural and some controllable. On a seasonal duration basis, the intensity and put from federally owned hydroelectric facilities and owns 75 of the water flow is driven percent of the region’s high-voltage transmission. It meets by snowpack in the mountains, the fullness of the reservoirs, of one-third approximately th firm and rainfall. On a short-term basis, the power generation is energy supply, region’s e water upstream locally and influenced by decisions mostly with power sold at cost. BPA gives preference to mu - to release to generate power, as well as local water-use decisions that nicipal and other publicly owned electric systems in allocating have nothing to do with the economics of power generation, its output. but are made for recreation, irrigation and wildlife consider- Both the Alberta Electric System Operator and British Colum - ations. The peak generation begins in the spring, when the interchange Net NWPP. the of - members are Hydro bia be snow melts, and may last into early summer. tween these two BAs and the United States tends to result When there is less water available, the Northwest may rely in net exports from the United States into Canada. Net inter- more on its coal and natural gas generation. It will occasion - change between U.S. and Canadian balancing authorities rep - ally import power from neighboring regions when loads are resents about one percent of total NWPP load. high. ICE The - Mid-Colum Northwest: the in points trading four has bia (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 on- peak 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 encompasses Arizona, The Sou thwest electric market the and (AZ/NM/SNV) Nevada Rocky uthern so Mexico, New Mountain Power Area (RMPA) subregions of the Western - Electric Coordinating Council (WECC). Peak demand is approx imately 42 GW in summer. There are approximately 50 GW of generation capacity, composed mostly of gas and coal units. Trading and Market Features - The Southwest relies on nuclear and coal generators for base The water forecast for affects the forward market electricity - load electricity, with gas units generally used as peaking re well as flow water daily The Northwest. e th in - con weather as sources. The coal generators are generally located in close influence the prices in daily physical market. When ditions the proximity to coal mines, resulting in low delivered fuel costs. there is an abundance of hydro generation, the Northwest will Some generation is jointly owned among multiple nearby utili - export as much as possible on the transmission lines leading ties, including the Palo Verde nuclear plant, a plant with three much so is there hours off-peak in Sometimes California. into units totaling approximately 4,000 MW, which has owners in generation that power prices are negative because the trans- California and the Southwest. mission lines are full and there is not enough local load to take all of the power. | C egulatory r nergy e ederal F ommission Energy Primer 70

77 Southwest Electric Region elocity Suite, ABB Source: V region is The summer-peaking AZ/NM/SNV and experiences high loads due to air conditioning demand. The daily high tem - peratures 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, creat- ing competition for the generation resources. | Energy Primer 71

78 Peak Demand CAISO CAISO’s all-time peak load was 50 GW in summer 2006. California Independent System Operator Import and Exports Up to about one-third of CAISO’s energy is supplied by im- two Southwest ports, principally from the primary sources: and Pacific Northwest the (Arizona, Nevada New Mexico) and (Oregon, Washington and British Columbia). Imports from increase the generally Northwest Pacific spring late the in when hydroelectric production peaks from increases in winter and runoff. snowmelt Market Participants CAISO’s market participants include generators, retail market - ers and utility customers, ranging from investor-owned utili - Pacific include which (IOUs), ties South (PG&E), Electric & Gas - ern California Edison (SCE), San Diego Gas & Electric (SDG&E), and others such as the Valley Electric Association, to some participants. financial and utilities municipal Membership and Governance board of a has O CAIS The - mem five of consists that governors Source: V elocity Suite, ABB by and r governo the - Califor the app confirmed bers ointed by nia 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. Market Profile CAISO uses an informal stakeholder process to propose solu - FERC. may that problems at to tions a require filing ultimately Unlike other RTOs, which have a formal committee structure, Geographic Scope CAISO’s stakeholder process generally consists of rounds of corporation benefit public nonprofit California a is CAISO dialogue with stakeholders on major policy issues. started in 1998 when the state restructured its electric power industry. The CAISO manages wholesale electricity markets, Transmission Owners centrally dispatching electricity generation facilities. In man - The Participating Transmission Owners (PTOs) in the CAISO aging the grid, CAISO provides open access to the transmis - control include: area sion system and performs long-term transmission planning. It Electric and Gas Pacific • Co. manages energy and ancillary markets in day-ahead and real- Southern California Edison • time markets and is responsible for regional reliability. | C egulatory r nergy e ederal F ommission Energy Primer 72

79 San Diego Gas and Electric, • Market Features Valley Electric Association • • Municipal utilities such as Vernon, Anaheim and Riverside Energy Markets Chronic Constraints Load pockets that are chronically constrained include San Di - Day-Ahead Market Basin, and Fran No rth Coast/North Bay (San ego, - Los Angeles cisco). The day-ahead market allows participants to secure prices for electric energy the day before the operating day and hedge Transmission Planning day One against price fluctuations that can occur in real time. participants dispatch, l actua ahead of offers supply submit CAISO conducts an annual transmission planning process with and demand bids for energy. These bids are applied to each stakeholders that includes both short-term and long-term hour of the day and for each pricing location on the system. projects. and - offers the From sup aggregate constructs CAISO bids, Supply Resources ply and demand curves for each location. The intersection of generating By these includes mix the capacity, plant sources: these curves identifies the market-clearing price at each lo - cation for every hour. Supply offers below and demand bids Generation Mix to said are clear, are they meaning above the identified price that are entered clear bids and Offers scheduled for dispatch. into a pricing software system along with binding transmis - sion constraints to produce the locational marginal prices (LMP) for all locations. day-ahead the in scheduled are offers settlement Generator paid the day-ahead LMP for the megawatts accepted. Sched- Source: Velocity Suite, ABB uled suppliers must produce the committed quantity during real-time or buy power from the real-time market to replace Demand Response what was not produced. Demand response participation in the wholesale energy mar- ket is currently limited to a small amount of demand associ - Likewise, wholesale buyers of electricity whose bids clear in ated with water pumping loads. Other demand response in the day-ahead market settlement pay for and lock in their California consists of programs for managing peak summer right to consume the cleared quantity at the day-ahead LMP. demands operated by the state’s electric utilities. In general, Electricity use in real time that exceeds the day-ahead pur - these demand-response programs may be triggered based on chase is paid for at the real-time LMP. criteria that are internal to the utility or when CAISO issues a Flex Alert. Flex Alerts also inform consumers how and when Real-Time Market to conserve electricity usage. CAISO must coordinate the dispatch of generation and de - mand resources to meet the instantaneous demand for electricity. While the day-ahead energy market produces the fin use schedule and for ancial terms of energy production and the operating day, a number of factors can change that sched- | Energy Primer 73

80 mand. Spinning and nonspinning resources are used to main ule. Thus, to meet energy needs within each hour of the cur - - tain system frequency and stability during emergency oper- rent day the CAISO operates a spot market for energy called the real-time market. ating conditions (such as unplanned outage of generation or transmission facilities) and major unexpected variations in real-time market uses final day-ahead schedules for re - The load. Spinning and nonspinning resources are often referred sources within the ISO and imports and exports as a starting to collectively as operating reserves. then operates a fifteen minute market to adjust re - point. It balance s, and then a five minute to source schedule market Capacity Markets generation and loads. Capacity markets provide a means for LSEs to procure capac - Prices resulting from the real-time market are only applicable ity needed to meet forecast load, or resource adequacy (RA) to incremental adjustments to each resource’s day-ahead requirements, and to allow generators to recover a portion of schedule. Real-time bids can be submitted up to 75 minutes incentives economic provide also They - at to their fix ed costs . before the start of the operating hour. tract investment in new and existing supply-side and demand- side capacity resources needed to maintain bulk power sys- Ancillary and Other Services tem reliability requirements. Ancillary services are those functions performed by electric generating, transmission, and system-control equipment to The CAISO does not operate a formal capacity market, but support the reliability of the transmission system. RTOs pro- it does have a mandatory RA requirement. The program re- cure or direct the supply of ancillary services. - quires that LSEs procure 115 percent of their aggregate sys on mar - a monthly tem load reserve different a unless basis, CAISO procures four ancillary services in the day-ahead and gin is mandated by the LSE’s local regulatory authority. The real-time markets: program provides deliverability criteria each LSE must meet, up must be able • Regulation up: Units providing regulation as well as system and local capacity requirements. Resources to move quickly above their scheduled operating point in counted for RA purposes must make themselves available to response to automated signals from the ISO to maintain the CAISO day-ahead and real-time markets for the capacity the frequency on the system by balancing generation and for which they were counted. demand. Units down: providing Regulation • must down regulation Market Power Mitigation be able to move quickly below their scheduled operating point in response to automated signals from the ISO. In electric power markets, mainly because of the largely non- providing Resources reserve: Spinning • spinning reserves - storable nature of electricity and the existence of transmis with the grid (online, or spinning) must be synchronized sion constraints that can limit the availability of multiple sup - and be able to respond within 10 minutes. This is more pliers to discipline market prices, some sellers from time to reliable than nonspinning reserves because it is already time have the ability to raise market prices. Market power synchronized. and online mitigation is a market design mechanism to ensure competi - reserve: Nonspinning nonspinning providing • Resources even offers present. not are conditions competitive tive when must be able to and reserves synchronize with the grid respond within 10 minutes. - Market power may need to be mitigated systemwide or lo cally when the exercise of market power may be particularly Regulation up and regulation down are used continually to a concern for a local area. For example, when a transmission maintain system frequency by balancing generation and de- constraint creates the potential for local market power, the | C egulatory r nergy ommission ederal F e Energy Primer 74

81 RTO may apply a set of behavioral and market outcome tests costs that arise with transmission congestion over a selected path, or source-and-sink pair of locations on the grid. The CRR to determine if the local market is competitive and if genera- shoul d be adjusted to approximate price levels that also requires its holder to pay a charge for those hours when tor offers would be seen in a competitive market – close to short-run congestion occurs in the opposite direction of the selected marginal costs. source-and-sink pair. CRRs are monthly or quarterly products. CRRs can be bought at auction or allocated by CAISO. Allo- for the specific a cated CRRs receive congestion value path, Special Provisions for Resources Needed to similar to a converted FTR. CAISO also allocates open market Ensure Grid Reliability CRR auction revenue to LSEs based on their physical participa - tion in the market, similar to an ARR in other markets. An RMR contract acts as an insurance policy, assuring that the CAISO has dispatch rights in order to reliably serve load in lo- cal import constrained areas. RMR contracts also help to miti- Virtual Transactions gate any local market power that one or more units may have. The amount of generation capacity under RMR contracts CAISO’s market includes a virtual transactions feature, termed dropped when local RA requirements were introduced. With convergence bidding, that allows more participation in the more local resources being procured through RA contracts, day-ahead price-setting process, allows participants to man - ntly decrease its RMR designa - age risk, and enables arbitrage that promotes price conver- the CAIS O was able to significa tions in much of the system. Remaining generators with RMR gence between the day-ahead and real-time energy markets. contracts are located primarily near the San Francisco and Los CAISO’s convergence bidding includes both virtual supply and virtual demand transactions. A virtual supply transaction is an Angeles areas. buy a and price day-ahead e th at sell to offer real- the at to bid time price. A virtual demand transaction is a bid to buy at the The price and an offer to sell at the real-time price. day-ahead virtual supply offer and the virtual demand bid may be submit - ted at any eligible pricing node in the CAISO system and there quirement The load. or physical - finan is no re for generation cial outcome for a particular participant is determined by the day-ahead between the hourly difference and real-time LMPs at the location at which the offer or bid clears. Credit Requirements - that a requirements market par CAISO’s tariff includes credit ticipant needs to meet in order to participate in the market. Financial Transmission Rights effects the mitigating in assist requirements credit The - de of - faults that would otherwise be borne among all market partic As discussed earlier in this chapter, FTRs provide market par - ipants. CAISO assesses and calculates the required credit dol- ticipants with a means transmission to offset or hedge against lar amounts for the segments of the market in which an entity congestion costs in the day-ahead market. In California, FTRs requests to participate. The market participant may request are referred to as Congestion Revenue Rights (CRR). A CRR is an unsecured credit allowance subject to certain restrictions an instrument that entitles the CRR holder to a payment for | Energy Primer 75

82 – e.g., CAISO must review the entity’s request relative to vari - creditworthiness-related specifications such tangible ous as 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 set- tles 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 imbal - ance market (E IM) with PacifiC orp’s two balancing authority ACW). areas, PacifiCor p East (P ACE) and PacifiCorp W est (P Pacifi the extended into - CAISO its existing real-time market Corp to automatically dispatch resources to meet intra-hour may transfer imbalance energy through a limited amount of changes in energy demand and supply. Resources participate transmission capability. Consequently, prices and supply are in the EIM voluntarily and only resources that register to par - largely determined by resources within each area. CAISO’s De- ticipate may actually bid into the EIM for the 15- and 5- min - partment of Market Monitoring serves as the market monitor ute market runs. Load buys imbalance energy directly from for the EIM. While the CAISO’s operations remain under the example, PacifiCorp, the in largest LSE P ACE and the EIM. For CAISO Board of Governors, an EIM Transitional Committee ad- PACW areas, buys imbalance energy through the EIM. Other vises CAISO’s board of governors and is developing a proposal entities that may purchase imbalance energy include wind Among benefits, the EIM other for long-term EIM governance. generators that seek to match their generation supply with may provide a broader footprint for incorporating renewable contracted demand. generation and an opportunity to improve the economic ef- generation of ficiency dispatch. The three balancing authorities – CAISO, PACE, and PACW – | C egulatory r nergy e ederal F ommission Energy Primer 76

83 Peak Demand ISO-NE New England’s all-time peak load was 28 GW in summer 2006. New England Independent System Operator 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 directions alternate in flows power ork, Y New on depending market conditions. Market Participants The New England Power Pool (NEPOOL) consists of six sec- sector; end-user (1) tors: - sup (3) entities; owned publicly (2) plier sector; (4) transmission sector; (5) generation sector; and (6) alternative resources. Membership and Governance 10-member, a by entity governed not-for-profit a is ISO-NE independent, non-stakeholder board of directors. The sitting to people elect board the of members board fill vacancies. Source: Velocity Suite, ABB Transmission Owners ISO-NE’s transmission include: owners • Central Maine Power Co. Market Profile New England Power Co. • • Northeast Utilities System Cos. Geographic Scope • NSTAR Electric Co. - As the RTO for New England, ISO-NE is responsible for oper • The United Illuminating Co. - ating wholesale power markets that trade electricity, capac Vermont Electric Cooperative Inc. • ity, transmission congestion contracts and related products, Chronic Constraints in addition to administering auctions for the sale of capacity. Constraints in the ISO-NE are concentrated in the Northeast ISO-NE operates New England’s high-voltage transmission Massachusetts-Boston com England New However, - zone. network and performs long-term planning for the New Eng - pleted a series of major transmission projects in 2009 to - land system. ISO-NE serves six New England states: Connecti improve reliability, including projects serving Boston, south - cut, Mai ne, Mas sachusetts, Hampshire, Rhode Island and New western Connecticut and southeastern Massachusetts. Fur - Vermont. | Energy Primer 77

84 ahead LMP. The participant is paid the day-ahead LMP thermore, it continues to assess and bolster its transmission for the cleared interruptions, and real-time deviations are system. charged or credited at the real-time LMP. Transmission Planning Each year, ISO-NE prepares a comprehensive 10-year regional system plan (RSP) that reports on the results of ISO system Market Features planning processes. Each plan includes forecasts of future loads (i.e., the demand for electricity measured in megawatts) by demand may be satisfied adding this and addresses how Energy Markets supply resources; demand resources, including demand re- efficiency; new or upgraded trans - energy sponse and and Day-Ahead Market mission New England summarizes year’s facilities. Each plan The day-ahead energy market allows market participants to needs in needs, areas, and includes solu - as well as the specific secure prices for electric energy the day before the operating - tions and processes required to ensure the reliable and eco fluctuations price against hedge and day real in occur can that nomic performance of the New England power system. time. One day ahead of actual dispatch, participants submit supply are bids These energy. for bids demand and ap - offers Supply Resources plied to each hour of the day and for each pricing location on capacity, the By plant mix includes these sources: generating the system. Generation Mix dec - In the day-ahead energy market, incremental offers and remental and bids (virtual supply offers 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 mar - ket participants can use to hedge their positions in the day- Source: Velocity Suite, ABB ahead energy market. Demand Response sup constructs - From the offers and bids, the RTO aggregate ply and demand curves for each location. The intersection of Currently, ISO-NE administers the following demand-response each the identifies curves these price market-clearing - lo at market: electricity wholesale England the for programs New every for cation bids demand and below offers Supply hour. These : Real-Time Demand Response Resources (RTDR) • above cleared are price - Of scheduled. are and identified the resources are required to respond within 30 minutes of - fers and bids that clear are entered into a pricing software sys the ISO’s instructions. tem along with binding transmission constraints to produce - Real-Time Emergency Generation Resources (RTEG): Re • the LMPs for all locations. sources that the ISO calls on to operate during a 5 percent voltage reduction that requires more than 10 minutes to Real-Time Market implement. They must begin operating within 30 minutes ISO-NE must coordinate the dispatch of generation and de- of receiving a dispatch instruction. mand resources to meet the instantaneous demand for elec - Transitional Price-Response Demand : • optional program An tricity. Supply or demand for the operating day can change that allows market participants with assets registered for a variety of reasons, including unforeseen generator or RTDRs to offer load reductions in response to day- as | C egulatory r nergy ommission ederal F e Energy Primer 78

85 electricity from neighboring control areas with at least one transmission outages, transmission constraints or changes from the expected demand. While the day-ahead energy mar- hour’s notice. schedule and financial terms of energy pro - ket produces th e duction and use for the operating day, a number of factors Must-Offer Requirements can change that schedule. Thus, ISO-NE operates a spot mar- ket for energy, the real-time energy market, to meet energy in rules Market must-offer include requirements for cer - RTOs needs within each hour of the current day. tain categories of resources for which withholding, a form of the exercise of market power, may be a concern. Where such generators, the offer, or it, comm must sellers ply, ap rules 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 trans - mission 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 mar - ket compensates generators for making available their un clears real-time energy market using supply offers, the ISO-NE loaded operating capacity that can be converted into electric sell to bids offers real-time load and and over energy or buy energy within 10 or 30 minutes when needed to meet system the external interfaces. For generators, the market provides contingencies, such as unexpected outages. The Regulation supply opportunities to offer additional - to help meet incre - Market compensates resources that ISO-NE instructs to in mental supply needs. LSEs whose actual demand comes in crease or decrease output moment by moment to balance the higher than that scheduled in the day-ahead energy market variations in demand and system frequency to meet industry may secure additional energy from the real-time energy mar- services in procures ISO-NE its ancillary specific The standards. ket. following: the include markets ancially energy market fin real-time settles the differences The Reserves: provided by resources Ten-Minute • Spinning - between the day-ahead scheduled amounts of load and gen grid to and generate the to synchronized already able - Differ generation. and load real-time actual the and eration electricity within 10 minutes. ences from the day-ahead quantities cleared are settled at the • resources by provided Reserves: Nonspinning Ten-Minute real-time LMP. not currently synchronized to the grid but of capable - In real time, ISO-NE will issue dispatch rates and dispatch tar starting and providing output within 10 minutes. five-minute megawatt and price are These gets. based signals - Nonspinning Thirty-Minute • resourc by provided Reserves: erators, the produce will which on gen of offers e aggregat the currently synchronized to the grid but capable of es not required energy production. Market participants are, through - starting and providing output within 30 minutes. request or imports offer of to allowed day, the out exports equipped resources • Regulation: provided by specially | Energy Primer 79

86 with the capability to increase or decrease their genera - Special Provisions for Resources Needed to tion output every four seconds in response to signals Ensure Grid Reliability they receive from ISO-NE to control slight changes on the system. - When a resource owner requests to withdraw from the ca pacity market (termed a “delist bid”) or to retire the resource and in sold Specialized ancillary services th at are not bought (termed a “non-price retirement request”), the ISO evaluates these ancillary service markets include voltage support and whether the resource is needed for reliability, such as when a - black-start capability. Voltage support allows the New Eng resource’s withdrawal could lead to a violation of a reliability land control area to maintain transmission voltages. Black- requirement – e.g., inadequate reserve margins or a loss of start capability is the ability of a generating unit to go from a electric system stability. shutdown condition to an operating condition and start deliv - ering power without assistance from a power system. ISO-NE In New England, the resource owner has the option to retire procures these services via cost-based rates. the unit or continue to operate it while the ISO works with supply or alternate engineering regional stakeholders to find Capacity Markets solutions that could allow the resource to retire and still main - tain grid reliability. Alternative solutions might include ob- In ISO-NE’s annual Forward Capacity Auction (FCA), both gen- taining emergency sources of generation or more expensive erator and demand resources offer capacity three years in ad - generation from outside the region. If no other alternative is vance of the period for which capacity will be supplied. The available, the ISO may compensate the unit through certain three-year lead time is intended to encourage participation payment provisions of the capacity market or by entering into - by new resources and allow the market to adapt to resourc a cost of service agreement with the resource owner while es leaving the market. Resources whose capacity clears the other options are pursued. FCA acquire capacity supply obligations (CSOs). ISO-NE held its first two FCA s in 2008 for the 2010-11 and 2011-12 delivery Financial Transmission Rights The first full year of years. cap acity market commitments be - gan on June 1, 2010. The FCA process includes the modeling New England FTRs are monthly and annual products that if load zones will be transmission constraints of to determine provide hedge market participants with a means or offset to import- or export-constrained. against transmission congestion costs in the day-ahead energy market. An FTR is an instrument that entitles the FTR holder Market Power Mitigation to a payment for costs that arise with transmission congestion over a selected path, or source-and-sink pair of locations on In ISO-NE, mitigation may be applied for physical withholding, the grid. The FTR also requires its holder to pay a charge for economic withholding, uneconomic production, virtual trans- those hours when congestion occurs in the opposite direction actions conduct has a material effect or the other conduct if - of the selected source-and-sink pair. The RTO holds FTR auc on prices or uplift payments. The market monitor uses de- tions to allow market participants the opportunity to acquire - fined th resholds to withhold identify ph ysical and economic FTRs or to sell FTRs they currently hold. In New England, ARRs ing and uneconomic generation, as well thresholds defined as represent the right to receive revenues from the FTR auctions. if determine whether bids and offers would, not mitigated, to ISO-NE allocates ARRs to both LSEs, in relation to historic load, cause effect material a on or uplift charges. LMPs and to entities who make transmission upgrades that increase the capability of the transmission system. | C egulatory r nergy ommission ederal F e Energy Primer 80

87 Virtual Transactions Settlements New England’s market includes a virtual transaction feature. RTOs must invoice market participants for their involvement Virtual transactions allow for more participation in the day- in their markets. Settlements is the process by which the RTO ahead price setting process, allow participants to manage determines the amounts to be paid associated with buying risk, and enables arbitrage that promotes price convergence and selling energy, capacity and ancillary services, and paying between the day-ahead and real-time markets. In ISO-NE’s ter- administrative charges. minology, virtual transactions consist of market participants ISO-NE calculates, accounts for and settles all charges and and decrement bids in the day- submitting increment offers payments based on received settlement quality meter data. An increment offer is an offer to sell ahead energy market. The RTO conducts settlements for transactions related to the specific location in the day-ahead energy market energy at a various wholesale electricity markets, market products, and which is not associated with a physical supply. An accepted in - other services including energy, capacity, ancillary services, specified generation at the offer in scheduled crement results FTR charges and payments, among other charges. The RTO location in the day-ahead energy market. A decrement bid is a settles for both the day-ahead and real-time markets. specific location in the day-ahead a bid energy purchase to at energy market which is not associated with a physical load. An accepted decrement bid results in scheduled load at the day-ahead energy market. The par - specified location in the ticipant receives the day-ahead LMP for each megawatt of virtual supply that clears in the day-ahead energy market and to the real-time LMP at the same obligated financially is pay 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 par that a market credit - tariff ISO-NE’s requirements includes ticipant needs to meet in order to participate in the market. in mitigating the effects of de - The credit requirements assist faults that would otherwise be borne among all market par- ticipants. 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 accordance with tariff participant market each for in formulas specifications that include various creditworthiness-related such as tangible net worth and total amounts due and owing to the ISO-NE market. | Energy Primer 81

88 market and combined its 24 separate balancing areas into a MISO single balancing area. In 2013, the RTO began operations in Midcontinent Independent System Operator the MISO South region, including the utility footprints of En - tergy, 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 Ohio to Kentucky and Energy PJM. Import and Exports - MISO has interconnections with the PJM and Southwest Pow er 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 sys- tems. MISO is a net importer of power overall, but the inter- change with so me areas can flow in either direction, depend - ing on the relative loads and prices in the adjoining regions. of part large supplies Hydro Manitoba a load with its MISO’s excess capacity, particularly in the summer. Source: Velocity Suite, ABB Market Participants MISO includes approximately 40 transmission owners, whose Market Profile assets define the - market area. MISO’s market partici MISO pants include generators, power marketers, transmission-de - Geographic Scope pendent utilities and load-serving entities. MISO operates the transmission system and a centrally dis- patched market in portions of 15 states in the Midwest and Membership and Governance the South, extending from Michigan and Indiana to Montana - An independent board of directors of eight members, includ and from the Canadian border to the southern extremes of ing the president, governs MISO. Directors are elected by the Louisiana and Mississippi. The system is operated from three MISO membership from candidates provided by the board. Carmel, control Indiana; centers: Eagan, Minnesota; and Little Rock, Arkansas. MISO also serves as the reliability coordinator An advisory committee of the membership provides advice to for additional systems outside of its market area, primarily to - the board and information to the MISO stakeholders. Mem the north and northwest of the market footprint. bership includes entities with an interest in MISO’s operation, such as state regulators and consumer advocates, as well as power a not was MISO organizing an ISO in as pool before transmission owners, independent power producers, power December 2001. It began market operations in April 2005. In marketers and brokers, municipal and cooperative utilities January 2009, MISO started operating an ancillary services and large-volume customers. | C egulatory r nergy ommission ederal F e Energy Primer 82

89 committee. The plan is for two years. Once approved by the Transmission Owners - board, the plan becomes the responsibility of the transmis transmission in MISO owners include: The sion owners. • Alliant Energy American Transmission Co. • Supply Resources • Ameren (Missouri and Illinois) plant sources: By these includes mix generating the capacity, American Transmission Systems • Duke • Generation Mix Cleco • • Entergy Indianapolis Power and Light • • ITC • Michigan Public Power Agency NSP Companies (Xcel) • Northern Indiana Public Service Co. • Source: Velocity Suite, ABB Otter Tail Power • • MidAmerican Energy Demand Response Demand-side resources are able to participate in MISO’s mar- Chronic Constraints kets in providing capacity, energy in both the day-ahead and MISO has certain pathways that are more likely to become real-time markets and ancillary services. congested, but the likelihood and pattern of congestion in any area is subject to weather patterns, wind production and in - terchange with external regions. When load is high in the east - ern 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 particularly in Iowa. Higher wind pro - the northern direction, can can cause constraints in duction and areas localized some 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 con nects 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 own ers and other stakeholders who form the planning advisory | Energy Primer 83

90 Real-Time Market Market Features MISO must coordinate the dispatch of generation and demand resources to meet the instantaneous demand for electricity. Energy Markets Supply or demand for the operating day can change for a va - - riety of reasons, including unforeseen generator or transmis sion outages, transmission constraints or changes from the Day-Ahead Market expected demand. While the day-ahead market produces the The day-ahead market allows market participants to secure bulk the for trans terms financial and schedule physical - the of prices for electric energy the day before the operating day actions, a number of factors usually change the day-ahead re - real in occur can that fluctuations price against hedge and sult. Thus, MISO operates a spot market for energy, the real- time. One day ahead of actual dispatch, participants submit time energy market, to meet actual energy needs within each supply offers and demand bids for energy. These are ap - bids hour of the operating day. plied to each hour of the day and for each pricing location on the system. The real-time market is prepared for at the conclusion of the day-ahead market on the day before the operating day. MISO th e decremen In and day-ahead - offers incremental market, clears the real-time market using supply offers, real-time load bids) can also be tal bids (virtual supply offers and demand generators, the market provides For addi - and external offers. - submitted, although they are not associated with physical re offer to opportunities tional incremental meet help to supply sources or actual load. These INCs and DECs are tools market needs. LSEs whose actual demand comes in higher than what participants can use to hedge their real time commitments or was scheduled in the day-ahead market may secure additional to arbitrage the day-ahead to real-time price spread. energy from the real-time market. aggregate constructs RTO the and offers the From - sup bids, The the - be differences settles lly financia market real-time ply and demand curves for each location. The intersection of tween the day-ahead scheduled amounts of load and genera- - lo each at price market-clearing the identifies curves these tion and the actual real-time load and generation. Participants bids cation for every hour. Supply offers and demand below either pay or are paid the real-time LMP for the amount of load scheduled. above that bids and Offers the are price identified or generation in megawatt-hours that deviates from their day- clear are entered into a pricing software system along with ahead schedule. In real-time, MISO issues dispatch rates and binding transmission constraints to produce the locational and megawatt price five-minute are dispatch These targets. marginal prices (LMPs) for all locations. based on the signals aggregate offers of generators, which - will produce the required energy production. Market partici day-ahead settlement and offers schedule d in Generators the imports offer day, the throughout or re - are, to allowed pants are paid the day-ahead LMP for the megawatts accepted. quest exports of electricity from neighboring control areas by Scheduled suppliers must produce the committed quantity submitting transmission schedules into or out of MISO. during real-time or buy power from the real-time marketplace to replace what was not produced. In real-time, generators can also deviate from the day-ahead clearing schedule by self-scheduling, which means that MISO Likewise, wholesale buyers of electricity and virtual demand will run a given unit without regard to the unit’s economics un - whose bids to buy clear in the day-ahead market settlement less running the unit presents a reliability concern. During the pay for and lock in their right to consume the cleared quantity operating day, the real-time market acts as a balancing mar- at the day-ahead LMP. Electricity use in real-time that exceeds ket for load with physical resources used to meet that load. A the day-ahead purchase is paid for at the real-time LMP. market price for energy and for each of the ancillary services | C egulatory r nergy ommission ederal F e Energy Primer 84

91 interval is for each five-minute dispatch and the re - calculated Capacity Markets fi ve-minute prices are rolled into hourly prices for bill - sulting and real-time payment. Differences in the ing operation from Capacity markets are a construct to provide assurance to gov- the day-ahead clearing, including all virtual transactions, are ernment entities and to NERC a means for LSEs to prove they settled at the real-time price. have procured capacity needed to meet forecast load and to costs. fixed their of a recover to They allow generators portion also provide economic incentives to attract investment in new Must-Offer Requirements and existing supply- side and demand-side capacity resources. for requirements must-offer include Market RTOs in rules MISO maintains an annual capacity requirement on all LSEs certain categories of resources for which withholding, which based on the load forecast plus reserves. LSEs are required could be an exercise of market power, may be a concern. to specify to MISO what physical capacity, including demand Where the offer, or commit, must such sellers apply, rules resources, they have designated to meet their load forecast. generators, and schedule and operate the facilities, in the ap - This capacity can be acquired either through an annual capac - plicable market. ity auction, bilateral purchase, or self-supply. In MISO, generators who supply capacity to meet the RTO re- offer adequacy source for load are requirement required to Market Power Mitigation into the day-ahead and real-time markets for energy and the they are qualified. ancillary services for which In electric power markets, mainly because of the largely non - storable nature of electricity and the existence of transmis - sion constraints that can limit the availability of multiple sup - Ancillary and Other Services pliers to discipline market prices, some sellers from time to time have the ability to raise market prices. Market power Ancillary services are those functions performed by electric - mitigation is a market design mechanism to ensure competi generating, transmission and system-control equipment to tive offers even when competitive present. not are conditions support the transmission of electric power from generating resources to load while maintaining the reliability of the trans - mission system. RTOs procure or direct the supply of ancillary Special Provisions for Resources Needed to services. Ensure Grid Reliability MISO procures ancillary services via the co-optimized energy In MISO, a power plant owner seeking to retire or suspend a and ancillary services market and includes the following ser- MISO. from approval obtain evalu - must generator first MISO vices: ates plant retirement or suspension requests for reliability Spinning • already syn resources by provided Reserves: - need, and System Support Resource (SSR) designations are output within 10 chronized to the grid and able to provide made where reliability is threatened. Once an agreement has minutes. - been reached, SSRs receive compensation associated with re re • Supplemental (nonspinning) Reserves: provided by - maining online and available. capable but grid the to synchronized currently not sources of starting and providing output within 10 minutes. Financial Transmission Rights • Regulation: provided by specially equipped resources with the capability to increase or decrease their genera - off to - MISO FTRs provide market participants with a means tion output every four seconds in response to signals they set or hedge against transmission congestion costs in the receive to control slight changes on the system. | Energy Primer 85

92 day-ahead market. An FTR is an instrument that entitles the the day-ahead market, have their positions cleared in the real- offers market FTR holder to a payment for costs that arise with transmis - the real-time are time and bids Virtual price. at allowed in MISO at any pricing node or aggregate of pricing sion congestion over a selected path, or source-and-sink pair nodes. 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 Credit Requirements to in congestion difference the relative calculated are charges, prices in the day-ahead market across the selected FTR trans- market a that - requirements credit includes tariff MISO’s par mission path. MISO FTRs are monthly and annual products. ticipant needs to meet in order to participate in the market. de of effects mitigating in assist requirements credit the - The The RTO holds FTR auctions to allow market participants the faults that would otherwise be borne among all market par- opportunity to acquire FTRs, sell FTRs they currently hold, or ticipants. The RTO assesses and calculates the required credit to convert ARRs to FTRs. ARRs provide LSEs, and entities who dollar amounts for the segments of the market in which an make transmission upgrades, with a share of the revenues entity requests to participate. The market participant may re- generated in the FTR auctions. MISO allocates ARRs to trans - - quest an unsecured credit allowance subject to certain restric mission customers relative to historic usage, or upgraded ca - tions – e.g., the RTO must review the entity’s request relative pability, of the transmission system. tan as such specifications - to various creditworthiness-related gible net worth and credit scores. Virtual Transactions Settlements MISO’s market includes a virtual transaction feature that al - - lows a participant to buy or sell power in the day-ahead mar RTOs must invoice market participants for their involvement ket without requiring physical generation or load. Virtual in their markets. The RTO determines the amount owed as- transactions allow for more participation in the day-ahead sociated with buying and selling energy, capacity and ancillary price setting process, allow participants to manage risk, and services and paying various administrative charges. Settle- enables arbitrage that promotes price convergence between seven days in af MISO - are finalized ments for market activity the day-ahead and real-time markets. Cleared virtual supply ter the operating day and payable after 14 days. in virtual offers, or INCs) or the day-ahead en - (increment ergy market at a particular location in a certain hour creates a obligation bid the back buy to participant the for financial quantity in the real-time market at that location in that hour. Cleared virtual demand (decrement or virtual bids, or DECs) in to obligation financial creates a market day-ahead the the sell market. the in quantity bid real-time outcome financial The be a pa rticular participant is for determined by the difference - tween the hourly day-ahead and real-time LMPs at the loca - or bid clears. tion at which the offer offers MISO allows virtual bids and into its day-ahead market of determination the in included offers and bids where the are the LMP along with load resource offers and actual physical bids. Market participants, whose virtual transactions clear in | C egulatory r nergy ommission ederal F e Energy Primer 86

93 transmission network and performs long-term planning. NYISO New York Independent System Operator 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 electric - regularly flows from the Consolidated - ter ity Ed) (Con Edison ritory in upstate New York through PSEG territory in PJM, to phase Y ork City utilizing New 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 institutions, l financia electric utilities, traditional owners, local co-ops and industrials. Source: Velocity Suite, ABB Membership and Governance NYISO is governed by an independent 10-member board of directors and management, business issues and operating Market Profile - committees. Each committee oversees its own set of work ing groups or subcommittees. These committees comprise Geographic Scope transmission owners, generation owners and other suppliers, Prior to restructuring of the electric industry in the 1990s, New and power lic pub consumers, - re ariff T entities. environmental York’s private utilities and public power authorities owned and visions with filed procedures operating and rules market on operated New York’s electric system. Operation of the elec- the Commission are largely developed through consensus by tric grid was coordinated by a voluntary collaboration of the these committees. The members of the board, as well as all utilities and power authorities as the New York Power Pool employees, must not be directly associated with any market (NYPP). The creation of the New York Independent System participant or stakeholder. was The in FERC by ed authoriz 1998. (NYISO) Operator formal transfer of the NYPP’s responsibilities to the NYISO took place Transmission Owners on Dec. 1, 1999. NYISO’s include: transmission owners The NYISO footprint covers the entire state of New York. NYI- Corp. • Central Hudson Gas & Electric SO is responsible for operating wholesale power markets that Consolidated Edison Co. of New York • trade electricity, capacity, transmission congestion contracts, • Long Island Power Authority (LIPA) and related products, in addition to administering auctions for • New York Power Authority (NYPA) the sale of capacity. NYISO operates New York’s high-voltage | Energy Primer 87

94 ployed in energy shortage situations to maintain the reliability • New York State Electric and Gas Corp. (NYSEG) National Grid of the bulk power grid. Both programs are designed to reduce • • Orange & Rockland Utilities power usage by shutting down businesses and large power users. Companies, mostly industrial and commercial, sign up • Rochester Gas and Electric Corp. to take part in the programs. The companies are paid by NY - Chronic Constraints ISO for reducing energy consumption when asked to do so. - The chronic transmission constraints in NYISO are in the south Reductions are voluntary for EDRP participants. SCR partici- eastern portion of the state, leading into New York City and pants are required to reduce power usage and as part of their Long Island. As a result of their dense populations, New York - agreement are paid in advance for agreeing to cut power us City and Long Island are the largest consumers of electricity. age on request. and the north to - Consequently, energy flows from the west NYISO’s DADRP program allows energy users to bid their load ward these two large markets, pushing transmission facilities market. reductions to determined Offers day-ahead the into near their operational limits. This results in transmission con - be economic are paid at the market clearing price. Under day- straints in several key areas, often resulting in higher prices in loads the increase effectively may flexible DR, ahead amount the New York City and Long Island markets. of supply in the market and moderate prices. Transmission Planning The DSASP provides retail customers that can meet telemetry bid qualifi curtailment load their oth to lity abi the cations er and NYISO conducts a biennial transmission planning process with capability into the day-ahead market or real-time market to stakeholders that includes both short-term and long-term are provide reserve s and regulation service. Scheduled offers projects. paid the marketing clearing price for reserves or regulation. Supply Resources capacity, plant By these sources: the generating mix includes Market Features Generation Mix Energy Markets Day-Ahead Market The day-ahead market allows market participants to secure prices for electric energy the day before the operating day Source: Velocity Suite, ABB can that fluctuations price against hedge and real in occur time. One day ahead of actual dispatch, participants submit Demand Response - ap are bids These energy. for bids demand and supply offers (DR) NYISO - emer the programs: has demand-response four plied to each hour of the day and for each pricing location on - gency demand-response program (EDRP), the installed ca the system. pacity (ICAP) special case resources program (SCR), the and day-ahead offers supply virtual the In demand market, Day-Ahead Demand-Response Program (DADRP) and the De- - bids can also be submitted. These are tools market partici mand-Side Ancillary Services Program (DSASP). pants can use to hedge their positions in the day-ahead mar- Both the emergency and special cases programs can be de - ket. | C egulatory r nergy ommission ederal F e Energy Primer 88

95 aggregate bids, the RTO constructs sup - From the offers and and schedule the of terms energy production and use financial ply and demand curves for each location. The intersection of for the operating day, a number of factors can change that these curves identifies the market-clearing price at each loca - schedule. Thus, NYISO operates a spot market for energy, the our. and every demand bids h Supply offers below, for tion real-time energy market, to meet energy needs within each are scheduled. Offers and bids that above, the identified price hour of the current day. clear are then entered into a pricing software system along market outcomes are based Real-time on offers, real- supply with binding transmission constraints to produce the LMPs LSEs energy. buy or sell to bids time and offers and d loa whose for all locations. The NYISO refers to LMPs as locational based actual demand comes in higher than that scheduled in the marginal prices, or LBMPs. day-ahead market may secure additional energy from the real- Generators and offers schedule d in the day-ahead settlement time market. For generators, the market provides additional are paid the day-ahead LBMP for the megawatts accepted. additional meet help to needs. supply offer to opportunities Scheduled suppliers must produce the committed quantity differences the The settles lly financia market real-time - be during real-time or buy power from the real-time marketplace tween the day-ahead scheduled amounts of load and genera- to replace what was not produced. tion and the actual real-time load and generation. Those who Likewise, wholesale buyers of electricity and virtual demand - were committed to produce in the day-ahead are compensat whose bids to buy are accepted in the day-ahead market pay ed at (or pay) the real-time LBMP for the megawatts under- or for and lock in their right to consume the cleared quantity at over-produced in relation to the cleared amount. Those who the day-ahead LBMP. Electricity used in real-time that exceeds paid for day-ahead megawatts are paid (or pay) the real-time the day-ahead purchase is paid for at the real-time LBMP. LBMP for megawatts under- or over-consumed in real-time. occurs every generators minutes, as Real-time dispatch of five Hour-Ahead Market does the setting of the real-time prices used for settlement The hour-ahead market allows buyers and sellers of electric- purposes. Market participants may participate in the day- ity to balance unexpected increases or decreases of electricity ahead, hour-ahead, and the real-time market. closes. sub after the day-ahead market use Bids and offers are - mitted an hour ahead of time. Prices are set based on those Must-Offer Requirements and offers, generally for bids use in matching generation and load requirements, but those prices are advisory only. Hour- auction the NYISO capacity Under rules, entities that offer ahead scheduling is completed at least 45 minutes prior to capacity into an auction that is subsequently purchased by the beginning of the dispatch hour after NYISO reviews trans- into capacity of amount that offer the load are required to mission outages, the load forecast, reserve requirements and day-ahead energy market. This rule ensures that capacity sold oth hour-ahead gen eration and firm transaction bids, among - through the capacity auctions is actually delivered into the er things. market. Real-Time Market Ancillary and Other Services NYISO must coordinate the dispatch of generation and de - - mand resources to meet the instantaneous demand for elec Ancillary services are those functions performed by electric tricity. Supply or demand for the operating day can change for generating, transmission and system-control equipment to - a variety of reasons, including unforeseen generator or trans support the transmission of electric power from generating mission outages, transmission constraints or changes from resources to load while maintaining the reliability of the trans - the expected demand. While the day-ahead market produces | Energy Primer 89

96 rangements based on their forecasted peak load plus a mar- mission system. RTOs procure or direct the supply of ancillary service different three services. for auctions conducts gin. NYISO The months), six (covering auction period capability the durations: NYISO administers competitive markets for ancillary services the monthly auction and the spot market auction. that are required to support the power system. The two most ca ork New Y ork has important types of ancillary services are operating reserves pacity requirements for four zones: New Y - Island, Hudson V alley, and New Y ork-Rest Long City, and regulation. Operating reserves and regulation are typi Lower of State. The resource requirements do not change in the cally provided by generators, but NYISO allows demand-side providers to participate in these markets as well. Operating monthly auctions and ICAP spot market auctions relative to reserve resources can either be spinning (online with addi- the capability period auction. The shorter monthly auctions ability) or nonspinning are designed to account for incremental changes in LSE’s load but able to tional ramping (off-line, synchronize quickly). NYISO relies on start regulating re - and forecasts. sources that can quickly adjust their output or consumption in response to constantly changing load conditions to maintain Market Power Mitigation system balance. In electric power markets, mainly because of the largely non - NYISO relies ancillary of types The following the on services: storable nature of electricity and the existence of transmis - by resources reserves: spinning Ten-Minute • al - provided sion constraints that can limit the availability of multiple sup - ready synchronized to the grid and able to provide output pliers to discipline market prices, some sellers from time to within 10 minutes. time have the ability to raise market prices. Market power nonspinning reserves: provided by resources • Ten-Minute mitigation is a market design mechanism to ensure competi - but capable of not currently synchronized to the grid offers tive even when competitive conditions are not present. starting and providing output within 10 minutes. Market power may need to be mitigated on a systemwide ba - Thirty-Minute • - resourc by provided reserves: nonspinning sis or on a local basis. When a transmission constraint creates to the grid but es capable of not currently synchronized the potential for local market power, the RTO may apply a set starting and providing output within 30 minutes. of behavioral and market outcome tests to determine if the resources • Regulation: provided by with to capability the if local be and competitive is market should generator offers - increase or decrease their generation output within sec adjusted to approximate price levels that would be seen in a onds in order to control changes on the system. competitive market. Capacity Markets The categories of conduct that may warrant mitigation by NY- ISO include physical withholding, economic withholding and - Capacity markets provide a means for LSEs to procure capac - uneconomic production by a generator or transmission facil ity needed to meet forecast load and to allow generators to obtain ity to benefits from a transmission constraint. Physical a portion of their fixed costs. eco They also provide recover - provided energy withholding is not offering to sell or schedule nomic incentives to attract investment in new and existing by a generator or transmission facility capable of serving a NY- supply-side and demand-side capacity resources in New York ISO market. Physical withholding may include falsely declaring as needed to maintain bulk power system reliability require - trans an outage, refusing to - offer or schedule a generator or ments. operating mission making facility; an unj ustifiable change to parameters of a generator that reduces its availability; or op - In NYISO’s capacity market, LSEs procure capacity through erating a generator in real-time at a lower output level than installed-capacity (ICAP) auctions, self-supply and bilateral ar- | C egulatory r nergy e ederal F ommission Energy Primer 90

97 percent applicable the over $50/MW of increase an or increase the generator would have been expected to produce had the generator followed NYISO’s dispatch instructions. Economic reference level, whichever is lower, is the threshold for deter - - withholding is submitting bids for a generator that are unjusti mining whether economic withholding has occurred. In this not is generator dispatched. the that so high NYISO will instance, bids below $5/MW are not considered economic fiably - not impose mitigation unless the conduct causes or contrib withholding. If an entity’s bids meet these thresholds, the ap - plicable reference level is substituted for the entity’s actual utes to a material change in prices, or substantially increases bid to determine the clearing price. guarantee payments to participants. Price Caps Special Provisions for Resources Needed to Ensure Reliability an offer cap NYISO has of and day-ahead its for $1,000/MWh real-time markets. Generation owners within New York seeking to retire or sus- g enerator must pend a first ob tain - regu state from approval to floors. subject offer caps is City ork Y New for Capacity and lators. After an assessment, if the generator is found to be Y Offer ca or levels reference on based ps are City ork New in necessary for reliability purposes, the local transmission own - avoided costs. Capacity from generators within New York City er can be compelled to reach a contract (Reliability Support offered in each ICAP spot market auction, unless that must be Services Agreement) with the generator where compensation capacity has been exported out of New York or sold to meet provisions are included to continue operation of the plant un - ICAP requirements outside New York City. til the reliability need is resolved. Local Market Power Mitigation Financial Transmission Rights Generators in New York City are subject to automated market with offset to means participants market a or FTRs provide power mitigation procedures because New York City is geo - hedge against transmission congestion costs in the day-ahead - graphically separated from other parts of New York; plus, gen market. The NYISO refers to FTRs as Transmission Congestion erators in New York City have been deemed to have market - Contracts (TCCs). A TCC is an instrument that entitles the hold power. - er to a payment for costs that arise with transmission conges tion over a selected path, or source-and-sink pair of locations These automated procedures determine whether any day- (or nodes) on the grid. The TCC also requires its holder to pay ahead or real-time energy bids, including start-up costs bids a charge for those hours when congestion is in the opposite and minimum generation bids, but excluding ancillary services direction of the selected source-and-sink pair. Payments, or exceed the tariff’s thresho lds for economic withholding, bids, charges, calculated relative to the are difference in conges - and, if so, determine whether such bids would cause material tion prices in the day-ahead market across the selected FTR price two these If payments. rantee gua in changes or effects transmission path. tests are met, mitigation is imposed automatically. A related product, ARRs, provide their holders with a share of For example, the threshold for economic withholding regard- the revenue generated in the TCC auctions. In general, ARRs - ing energy and minimum generation bids is a 300 percent in are allocated based on historical load served. As with TCCs, over - refer applicable the or $100/MWh of increase an crease ARRs provide transmission owners and eligible transmission ence level, whichever is lower. Energy or minimum generation ers custom service transmission or offset an against hedge - below $25/MWh are bids not considered economic withhold congestion costs in the day-ahead market. ing. Regarding operating reserves and regulation bids, a 300 | Energy Primer 91

98 Credit Requirements tariff includes credit requirements NYISO’s that a market par - ticipant needs to meet in order to participate in the market. credit The requirements assist in mitigating the effects of - de faults that would otherwise be borne among all market par- ticipants. 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 re- - quest an unsecured credit allowance subject to certain restric tions – e.g., NYISO must review the entity’s request relative to various invest as such specifications creditworthiness-related - ment grade or equivalency rating and payment history. Settlements Virtual Transactions RTOs must invoice market participants for their involvement NYISO’s market includes a virtual transaction feature that al- in their markets. Settlements is the process by which the RTO lows a participant to buy or sell power in the day-ahead market determines the amounts owed and to be paid associated with - without requiring physical generation or load. Virtual transac - buying and selling energy, capacity, ancillary services and pay tions allow for more participation in the day-ahead price set- ing various administrative charges. ting process, allow participants to manage risk, and enables NYISO uses a two-settlement process for its energy markets. arbitrage that promotes price convergence between the day- based and bids The first settlement offers, is on day-ahead ahead and real-time markets. Cleared virtual supply (virtual of- which clear the market and are scheduled. The second settle- fers) in the day-ahead energy market at a particular location in ment is based on the real-time bids and the corresponding participant certain hour creates a a financi al obligation for the real-time dispatch. to buy back the bid quantity in the real-time market at that location in that hour. Cleared virtual demand (virtual bids) in the the day-ahead market creates a financial obligation to sell market. quantity in the real-time bid The financial outcome is determined day-ahead hourly the between difference the by LBMPs at the location at which the offer or bid and real-time takes zonal a on place level, NYISO in bidding Virtual clears. not a nodal level. | C egulatory r nergy ommission ederal F e Energy Primer 92

99 Peak Demand PJM PJM’s all-time peak load was 165 GW in summer 2011. The PJM Interconnection Imports and Exports PJM has interconnections with Midcontinent ISO and New York ISO. PJM also has direct interconnections with the Ten - nessee Valley Authority (TVA), Progress Energy Carolinas and the Virginia and Carolinas Area (VACAR), among other sys- tems. PJM market participants import energy from, and ex- port 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, trans - Source: Velocity Suite, ABB mission owners, electric distributors, power marketers, elec- tric distributors and large consumers. Market Profile Membership and Governance PJM has a two-tiered governance model consisting of a board Geographic Scope of managers and the members committee. PJM is governed elect. The by a 10-member board, nine of whom PJM members The PJM Interconnection operates a competitive wholesale board appoints the tenth, the president and CEO, to supervise - electricity market and manages the reliability of its transmis generally responsible for day-to-day operations. The board is sion grid. PJM provides open access to the transmission and and efficiency oversight of system reliability, operating short performs long-term planning. In managing the grid, PJM cen- board ensures that no member and long-term planning. The trally dispatches generation and coordinates the movement undue or group of members exerts influence. of wholesale electricity in all or part of 13 states (Delaware, Michigan, , Kentucky, Maryland, Indiana New Jersey, Illinois, The members committee, which advises the board, is com - North Carolina, Ohio, Pennsylvania, Tennessee, Virginia and power posed of five voting sectors re presenting generators, West Virginia) and the District of Columbia. PJM’s markets in - transmission owners, electric distributors, power marketers clude energy (day-ahead and real-time), capacity and ancillary and large consumers. services. Transmission Owners PJM was founded in 1927 as a power pool of three utilities PJM include: in transmission owners The largest serving customers in Pennsylvania and New Jersey. In 1956, with the addition of two Maryland utilities, it became the AEP • • First Energy Pennsylvania-New Jersey-Maryland Interconnection, or PJM. • PSE&G PJM became a fully functioning ISO in 1996 and, in 1997, it in - • Dominion troduced markets with bid-based pricing and locational mar- Philadelphia Electric • ket pricing (LMP). PJM was designated an RTO in 2001. • Commonwealth Edison | Energy Primer 93

100 Chronic Constraints Supply Resources By largest constraints are in the Eastern Hub of P JM (New sources: these includes mix generating the capacity, plant The Jersey, Southeast Pennsylvania, and Delaware) and Northern Generation Mix Ohio. In general, transmission paths extending from genera- tion 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. Source: Velocity Suite, ABB Congestion on the eastern interface also constrains power Demand Response and Columbia, Northern of Baltimore flows from the District End-use customers providing demand response have the op - Virginia to New Jersey, Delmarva Peninsula and Philadelphia portunity to participate in PJM’s energy, capacity, synchro - load centers. The high-voltage, bulk power transmission nized can programs DR JM’s P markets. regulation and reserve pathway within portions of the states of Pennsylvania, West be grouped into emergency or economic programs. The emer- Virginia, Virginia and Maryland serve the densely populated gency program compensates end-use customers who reduce load centers of the metropolitan areas of Baltimore, the Dis - their usage during emergency conditions on the PJM system. trict of Columbia and Northern Virginia. The electricity needs Participation in the emergency program may be voluntary or of Washington-Baltimore- Northern Virginia are supplied not mandatory and payments may include energy payments, ca - energy trans - only by local generation but also by significant pacity payments or both. There are three options for emer- fers to those areas. energy participation: and registration program gency only, In recent years, transmission congestion has not been as se- capacity only and capacity-plus-energy. vere, due to upgrades to the transmission system, including The economic program allows end-use customers to reduce construction of new transmission lines. Additionally, the avail- electricity consumption in the energy markets and receive a ability of lower-cost natural gas has helped reduce the need payment when LMPs are high. Under this program, all hours for the eastern portion of PJM to import power from the west. are eligible and all participation is voluntary. Participation in ram offer an submitting forms: three takes the prog the into Transmission Planning offer into an submitting clears; that market day-ahead the ransmission - Plan Expansion trans T Regional PJM’s identifies real-time market that is dispatched; and self-scheduling load mission system additions and improvements needed to keep providing while reductions End-use JM. P - cus to notification electricity test to conducted are Studies JM. P within flowing tomers participate in demand response in PJM through mem- the transmission system against national and regional reliabil - bers called curtailment service providers, or CSPs, who act ity standards. These studies look forward to identify future as agents for the customers. CSPs aggregate the demand of transmission overloads, voltage limitations and other reliabili - retail customers, register that demand with PJM, submit the ty standards violations. PJM then develops transmission plans - re and JM P reductions by payment for verification of demand to resolve violations that could otherwise lead to overloads ceive the payment from PJM. The payment is divided among and blackouts. the CSP and its retail customers based on private agreements between them. | C egulatory r nergy ommission ederal F e Energy Primer 94

101 expected demand. While the day-ahead energy market pro- Market Features terms duces production energy of financial and schedule the and use for the operating day, a number of factors can change that schedule. Thus, PJM operates a spot market for energy, Energy Markets called the real-time energy market, to meet energy needs within each hour of the current day. Day-Ahead Market real-time market PJM clears the using supply real-time offers, The day-ahead market allows market participants to secure over energy buy or sell to bids and offers and load external the prices for electric energy the day before the operating day - Real-time LMPs are interfaces. calculated at five-minute inter in real- occur and hedge aga inst price fluctu ations that can vals based on actual grid operating conditions as calculated in time. One day ahead of actual dispatch, participants submit PJM’s market systems. Generators that are available but not are bids These energy. for demand and offers supply bids - ap selected in the day-ahead scheduling may alter their bids for plied to each hour of the day and for each pricing location on use in the real-time market during the generation rebidding the system. period from 4 p.m. to 6 p.m.; otherwise, their original day- aggregate constructs RTO the bids, and offers the From - sup ahead market. real-time the for effect in remain bids market ply and demand curves for each location. The intersection of market-clearing these curves identifies the - lo price at each Ancillary and Other Services offers Supply hour. every for cation bids demand and below said are above the identified price are to clear, meaning they Ancillary services are those functions performed by electric that a into entered are clear bids and Offers scheduled. pricing generating, transmission and system-control equipment to software system along with binding transmission constraints support the transmission of electric power from generating to produce the LMPs for all locations. - resources to load while maintaining the reliability of the trans mission system. RTOs procure or direct the supply of ancillary the offers schedule d and in day-ahead settlement Generators services. are paid the day-ahead LMP for the megawatts accepted. Scheduled suppliers must produce the committed quantity services: ancillary for markets following the operates PJM during real-time or buy power from the real-time marketplace • Regulation: corrects for changes in electricity short-term to replace what was not produced. stability use might affect the that of the power system. grid the if electricity • Synchronized has reserves: supplies Likewise, wholesale buyers of electricity whose bids to buy an unexpected need for more power on short notice. clear in the day-ahead market settlement pay for and lock in reserves Day-ahead scheduling PJM (DASR): allows • to their right to consume the cleared quantity at the day-ahead to schedule sufficient generation preserve reliability LMP. Electricity use in real-time that exceeds the day-ahead during unanticipated system conditions throughout the purchase is paid for at the real-time LMP. operating day. Regulation service matches generation with very short-term Real-Time Market changes in load by moving the output of selected resources PJM must coordinate the dispatch of generation and demand up and down via an automatic control signal. In addition, resources to meet the instantaneous demand for electricity. PJM schedules operating reserves in the day-ahead market, Supply or demand for the operating day can change for a va - and resources that provide this service are credited based on 30-minute and of their offer prices. Reserve consists 10-minute riety of reasons, including unforeseen generator or transmis - products. sion outages, transmission constraints or changes from the | Energy Primer 95

102 com Annual auctions are referred to as base residual auctions - is what of Synchronized reserves are the equivalent (BRAs). LSEs that are able to fully supply their own capacity monly referred to as spinning reserves, providing 10-minute - generator need can choose not to participate in the auctions. Most ca reserves from a grid. that is synchronized to the pacity is procured through self-supply and contracted (bilater- The DASR is the primary market mechanism for procuring al) resources and the auctions procure any remaining needed the 30-minute reserves. A resource will only be assigned an capacity. To mitigate the exercise of market power, the RPM amount of DASR corresponding to that amount of energy it market rules provide a test to determine whether each capac - - could provide within 30 minutes of a request. If the DASR mar ity seller has market power. If the seller fails that test, that ket does not result in procuring adequate scheduling reserves, seller’s bid is capped so as to replicate that seller’s avoidable PJM is required to schedule additional operating reserves. or opportunity costs. Furthermore, two ancillary services are provided on a cost blackstart service, which helps ensure the reliable basis: Market Power Mitigation (1) restoration of the grid following a blackout; and (2) reactive In electric power markets, mainly because of the largely power, which supports the voltages that must be controlled nonstorable nature of electricity and the existence of trans- for system reliability. mission constraints that can limit the availability of multiple suppliers to discipline markets, some sellers have the ability Capacity Markets to raise market prices. Market power mitigation is a market ensure when to mechanism design competitive offers even - Capacity markets provide a means for LSEs to procure capac competitive conditions are not present. ity needed to meet forecast load and to allow generators to They recover a portion of their fixed costs. also provide - eco - Market power may need to be mitigated on a systemwide ba nomic incentives to attract investment in new and existing sis or on a local basis where the exercise of market power may supply-side and demand-side capacity resources in PJM as - be a concern for a local area. For example, when a transmis needed to maintain bulk power system reliability. sion constraint creates the potential for local market power, the RTO may apply a set of behavioral and market outcome PJM’s capacity market is called the Reliability Pricing Model tests to determine if the local market is competitive and if (RPM). The RPM market was implemented in 2007 and is de- adjusted offers be generator price to approximate should signed to ensure the future availability of capacity resources, levels that would be seen in a competitive market – close to resources including demand-resources and energy-efficiency short-run marginal costs. that will be needed to keep the regional power grid operating reliably. RPM market design is based on three-year, forward- offer for implem enting test structural capping in P JM is The looking annual obligations for locational capacity under which called the three pivotal supplier test. Generation is subject to supply offers are cleared against a downward sloping demand occur caps when transmission offer - gen constraints such that curve, called the variable resource requirement (VRR) curve. erators are run out of merit order, which means that a higher- The VRR curve establishes the amount of capacity that PJM priced generator must be run due to a transmission constraint requires its LSE customers to purchase, and the price for that that prevents the use of available lower-priced generation. in each capacity zone (locational delivery area). Un - capacity, of out dispatched merit, P JM imposes offer are units When der RPM, when a locational delivery area is transmission-con - - capping for any hour in which there are three or fewer genera strained in the auction (i.e., limited in the amount of genera- tion suppliers available for redispatch that are jointly pivotal, tion that can be imported into those areas), capacity prices meaning they have the ability to increase the market price generally rise in that area relative to the overall PJM footprint. above the competitive level. | C egulatory r nergy ommission ederal F e Energy Primer 96

103 a payment for costs that arise with transmission congestion Price Caps 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 in $1,000/MWh offer cap the energy markets. has a PJM those hours when congestion is in the opposite direction of the selected source-and-sink pair. Payments, or charges, are calculated relative congestion in difference bined com the to prices in the day-ahead and real-time markets across the se - lected 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 con - verted to FTRs. As with FTRs, ARRs provide transmission own- and ers or offset an customers service transmission eligible hedge against transmission congestion costs in the day-ahead market. Virtual Transactions Special Provisions for Resources Needed to Ensure Grid Reliability PJM’s market includes a virtual transaction feature that allows a participant to buy or sell power in the day-ahead market with - A generator owner who wishes to retire a unit must request out requiring physical generation or load. Virtual transactions from PJM to deactivate the unit at least 90 days in advance of allow for more participation in the day-ahead price setting pro - the planned date. The owner includes in the request an esti- cess, allow participants to manage risk, and enables arbitrage mate of the amount of project investment necessary to keep that promotes price convergence between the day-ahead and if P turn, in JM, operation. in unit the retirement the analyzes real-time markets. Cleared virtual supply (increment or virtual would lead to a reliability issue. Additionally, the RTO esti- in - particu INCs) at or offers, energy day-ahead the a market - mates the period of time it would take to complete transmis for lar location in a certain hour creates a financial obligation sion upgrades necessary to alleviate the reliability issue. the participant to buy back the bid quantity in the real-time market at that location in that hour. Cleared virtual demand If PJM requests the unit to operate past the desired deacti- (decrement or virtual bids, or DECs) in the day-ahead market FERC for cost file owner generator the date, vation with may sell real- creates a financ ial obligation to the bid quantity in the recovery associated with operating the unit until it may be participant market. time particular The financial outcome for a deactivated. Alternatively, the owner may choose to receive day-ahead is determined by the difference between the hourly avoided cost compensation calculated according to PJM’s tar- tion loca the at LMPs real-time and bid or offer the which at iff. clears. Up-to-congestion (UTC) transactions are another type of transaction that may be submitted in the day-ahead energy Financial Transmission Rights market between any two buses either within PJM or between a bus within PJM and an external interface. UTC positions are means market participants with to offset or FTRs provide a liquidated in the real-time energy market. hedge against transmission congestion costs in the day-ahead market. An FTR is an instrument that entitles the holder to | Energy Primer 97

104 Credit Requirements SPP Southwest Power Pool requirements tariff includes credit PJM’s that a market partici - pant needs to meet in order to participate in the market. The mitigating effects in defaults of the credit requirements assist 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 vari - ous creditworthiness-related specifications such tangible as 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. 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 re- liable power supplies, adequate transmission infrastructure, and competitive wholesale electricity prices for its members. Based in Little Rock, Ark., SPP manages transmission in 14 Arkansas, Kansas, states: Louisiana, Minnesota, Mis - Iowa, souri, Montana, Nebraska, New Mexico, North Dakota, Okla- homa, 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 inde- pendent transmission companies. | C egulatory r nergy ommission ederal F e Energy Primer 98

105 six elected by the members to serve three-year terms, plus the In 2007, SPP began operating its real-time Energy Imbalance Service (EIS) market. In the same year, SPP became a FERC- SPP president, who is elected by the board. approved Regional Entity. The SPP Regional Entity serves as Supporting the board is the members committee, which pro- the reliability coordinator for the NERC region, overseeing vides input to the board through straw votes on all actions compliance with reliability standards. - pending before the board. The members committee is com In March 2014, SPP implemented its Integrated Marketplace posed of up to 15 people, including four representatives from that includes a day-ahead energy market, a real-time energy investor-owned utilities; four representatives of cooperatives; market, and an operating reserve market. SPP’s Integrated two representing municipal members; three representing Marketplace also includes a market for Transmission Conges - independent power producers and marketers; and two rep- Integrated Marketplace co-optimizes the tion Rights. The SPP resenting state and federal power agencies. The board is re- - deployment of energy and operating reserves to dispatch re quired to consider the members committee’s straw vote as sources on a least-cost basis. an indication of the level of consensus among members in ad- vance of taking any actions. In 2015, SPP expanded its footprint incorporating the Western Area Power Administration – Upper Great Plains region, the Transmission Owners Heartlands Con - Cooperative, and Power Electric Basin the SPP transmission owners (TOs) are investor-owned utilities, sumer Power District. The expansion nearly doubled SPP’s ser- municipals, cooperatives, state agencies and independent vice territory by square miles, adding more the 5 GW of peak - transmission companies. Some of the larger entities by in demand and over 7 GW of generating capacity. include: capacity stalled Peak Demand • Southwestern Electric Power Co. (AEP West) • OG&E Electric Services SPP’s all-time peak demand of 48 GW occurred in summer 2011. • Westar Energy Inc. • Southwestern Public Service Co. (Xcel Energy) Import and Exports • Kansas Plains City Energy) Power & Light Co. (Great SPP has interties with MISO, PJM, and Tennessee Valley Au - • Omaha Public Power District thority, among other systems. Additionally, SPP has two di- Nebraska Public Power District • rect-current (DC) interties with ERCOT and seven DC interties Operations • KCP&L Greater Missouri Energy) (Great Plains • Empire District Electric Co. to the western interconnect through New Mexico, Colorado, • Western Area Power Administration – Upper Great Plains Nebraska, South Dakota and Montana. At times, SPP is a net • Western Farmers Electric Cooperative importer of electricity and, at other times, SPP is a net export - er of electricity. Transmission Planning SPP conducts its transmission planning according to its Inte- Market Participants grated Transmission Planning process, which is a three-year SPP’s market participants include cooperatives, independent planning process that includes 20-year, 10-year, and near-term power producers, investor-owned utilities, power marketers, assessments designed to identify transmission solutions that smission tran cies, agen state utilities, municipal - nan fi ers, own address both near-term and long-term transmission needs. cial participants, and a federal power marketing administration. The Integrated Transmission Planning process focuses on identifying cost-effective regional transmission solutions, Membership and Governance ransmission Expansion which are identified in an annual SPP T SPP is governed by a seven-member board of directors, with Plan report. | Energy Primer 99

106 whose bids to buy clear in the day-ahead market settlement Supply Resources pay for and lock in their right to consume the cleared quantity plant capacity, the generating mix includes these sources: By at the day-ahead LMP. Electricity use in real-time that exceeds Generation Mix 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 Source: Velocity Suite, ABB use and production energy of op - the for and financial terms erating day, a number of factors can change that schedule. Thus, to meet energy needs within each hour of the current Market Features day, SPP operates a spot market for energy called the real- time market. Energy Markets The real-time market uses final day-ahead schedules for - re sources within the RTO and imports and exports as a starting Day-Ahead - gen balance to market five-minute a operates then It point. eration and loads. The day-ahead market allows market participants to secure prices for electric energy the day before the operating day Must-Offer Requirements and hedge aga inst price real- fluctu ations that can occur in time. One day ahead of actual dispatch, participants submit for requirements must-offer include RTOs in rules Market supply - ap are bids These energy. for bids demand and offers certain categories of resources for which withholding, which plied to each hour of the day and for each pricing location on could be an exercise of market power, may be a concern. the system. sellers apply, such rules Where the offer, or commit, must the the offers and bids, From - RTO constructs aggregate sup generators, and schedule and operate the facilities, in the ap - ply and demand curves for each location. The intersection of plicable market. these curves identifies the - lo each at price market-clearing In SPP, generators who supply capacity to meet the RTO re - cation every hour. Supply offers below and demand bids for requirement adequacy source load are required to offer for clear, meaning they are above the identified price are said to into the day-ahead and real-time markets for energy and the clear pricing Offers and bids that are entered into scheduled. a for services ancillary qualified. are they which software system along with binding transmission constraints to produce the LMPs for all locations. Ancillary and Other Services the offers and schedule in d day-ahead settlement Generators are paid the day-ahead LMP for the megawatts accepted. Ancillary services are those functions performed by electric Scheduled suppliers must produce the committed quantity generating, transmission and system-control equipment to during real-time or buy power from the real-time marketplace support the transmission of electric power from generating to replace what was not produced. - resources to load while maintaining the reliability of the trans mission system. Likewise, wholesale buyers of electricity and virtual demand | C egulatory r nergy e ederal F ommission Energy Primer 100

107 sign SPP ancillary services via the co-optimized energy - com when even offers competitive ensure to mechanism procures petitive conditions are not present. Market power may need and ancillary services market and includes the following ser- to be mitigated on a systemwide basis or locally. vices: Up Regula - • Regulation this reserves: Resources providing tion Up must be able to move quickly above their sched - uled operating point in response to automated signals from the RTO to maintain the frequency on the system by balancing generation and demand. Resources providing Regu - • Regulation Down reserves: lation 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. providing Reserves: Re Spinning • - Spinning Resources are already synchronized to the grid and available serves to serve load within a short period following a contin - gency event such as an unexpected failure or outage of generator, transmission line, or other electrical element. are that Resources and/or Reserves: Supplemental • on-line off-line but capable of being synchronized to the grid and to serve specified load following a period fully available following a contingency event. Capacity Markets SPP applies a set of behavioral and market outcomes tests requires SPP does not offer a capacity market. it However, to determine if the local market is competitive and if genera- (ca supply energy sufficient - to participant market each have that levels price approximate tor to offers shoul d be adjusted pacity) to cover its energy obligations. SPP performs a supply competitive close prices offer would be seen in a i.e., market – adequacy analysis for each market participant based on a load to short-run marginal costs. SPP’s mitigation test includes a forecast, resource plan, ancillary service plan and schedules local market power test, a pivotal supplier test, and a mar - received from market participants. This analysis is performed ket impact test. Where mitigation measures are triggered by for each hour of the next operating day, with results available the tests, SPP generates a mitigated market solution that the by 3 p.m. of the day prior to the operating day. RTO then uses for dispatch, commitment, and settlement purposes. Market Power Mitigation Price Caps In electric power markets, mainly because of the largely non - storable nature of electricity and the existence of transmis - offer an cap $1,000/MWh. of SPP employs sion 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 de | Energy Primer 101

108 tions allow for more participation in the day-ahead price set- Special Provisions for Resources ting process, allow participants to manage risk, and enables Needed to Ensure Grid Reliability arbitrage that promotes price convergence between the day- ahead and real-time markets. Cleared virtual supply (virtual of- SPP prepares annual reliability studies as part of its system fers) in the day-ahead energy market at a particular location in planning responsibilities. In the event that studies reveal a a certain hour creates a financi al obligation participant the for potential constraint on SPP’s ability to deliver power to a local to buy back the bid quantity in the real-time market at that lo - area on the transmission system, the RTO works with regional cation in that hour. Cleared virtual demand (virtual bids) in the find transmission, proce to stakeholders operating - alternate bid the sell fin a creates market day-ahead to obligation ancial dure, or generation solutions for the constraint and thus main - real-time the in quantity The financial outcome is market. de - tain grid reliability. SPP parties will determine an appropriate between and day-ahead hourly the difference the by termined sharing of the costs, and, if unable to reach agreement, the LMPs bid clears. real-time at the location at which the offer or RTO will submit a proposed cost sharing arrangement to the Commission for approval. Credit Requirements Financial Transmission Rights requirements - partici credit includes tariff SPP’s a that market pant needs to meet in order to participate in the market. The Financial FTRs provide market participants with a means to requirements assist in defaults of effects the mitigating credit costs in the offset or congestion hedge transmission against that would otherwise be borne among all market participants. - day-ahead market. SPP refers to FTRs as Transmission Con The RTO assesses and calculates the required credit dollar gestion Rights (TCRs). A TCR is an instrument that entitles the amounts for the segments of the market in which an entity holder to receive compensation, or requires the holder to pay requests to participate. The market participant may request a charge, for costs that arise with transmission congestion an unsecured credit allowance subject to certain restrictions – over a selected path, or source-and-sink pair of locations on e.g., the RTO must review the entity’s request relative to vari - the grid. A TCR provides the holder with revenue, or charges, ous specifications such as tangible creditworthiness-related difference in congestion prices in the to equal day-ahead the financial net various and measures. worth market across the selected TCR transmission path. SPP TCRs are monthly and annual products. Settlements A related product, ARRs, provide their holders with a share of the revenue generated in the TCR auctions. In general, ARRs RTOs must invoice market participants for their involvement are allocated based on historical load served. As with TCRs, in their markets. Settlement is the process by which the RTO ARRs provide transmission owners and eligible transmission determines the amounts owed associated with buying and transmission against hedge or offset an ers custom service selling energy, capacity and ancillary services, and paying ad- congestion costs in the day-ahead market. ministrative charges. SPP has a two-settlement system, one each for the day-ahead Virtual Transactions and real-time markets. The SPP settlement process calculates - quantities of energy, ancillary services, TCRs, virtual transac SPP’s market includes a virtual transaction feature that allows tions, among other market features. a participant to buy or sell power in the day-ahead market without requiring physical generation or load. Virtual transac - | C egulatory r nergy e ederal F ommission Energy Primer 102

109 P roducts E o il & P EtrolEum rud 4. u.s. c m arkEts 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. U.S. Petroleum Products Supply in 2014 Petroleum Accounts for Most of the Energy (Million gallons/day) Consumption in the Transportation Sector Source: Derived from EIA data Source: Derived from EIA data FERC Jurisdiction Unlike methane, the primary component of pipeline grade Petroleum is both pro - natural gas, petroleum is not consumed in its natural form; duced domestically and The Federal Energy Regulatory refined can into a number of products that instead, be it is imported from a number Commission’s jurisdiction used for numerous applications. In the U.S., the largest share of countries. The same is over the oil markets is limited of crude oil, approximately 90 percent, is consumed as trans- true for petroleum prod- to setting pipeline transpor - tation rates and ensuring portation fuels, including gasoline, diesel, and jet fuel. Other ucts, especially gasoline, open access in the pipeline uses include heating, power generation, and petrochemical diesel fuel, and jet fuel. system. feedstocks used to manufacture a variety of products includ - The percent of imported pharmaceuticals, and fertilizers, plastics, construction ing petroleum and petroleum materials. 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 | Energy Primer 103

110 in althoug amounts are produced significant other h Dakota, in tiny spaces within sedimentary rocks, and near the surface refineries, convert the crude oil into states. usable in tar (or oil) sands. In its natural state, crude oil ranges in U.S. which products, are found throughout the country, but are heavily density and consistency, from very thin, light-weight and vola- extremely Its tile fluidity thick, concentrated on the Gulf Coast. oil. heavy-weight semi-solid to color can vary from a light golden yellow to a deep black. Petroleum Benchmark Crude Oil Unlike natural gas, which is a simple molecule consisting of 1 oil crude benchmark A oil crude specific widely a is that is atoms as petroleum (CH4), carbon hydrogen four and atom bought and sold at well-traded locations with commonly found in the ground is a mixture of hydrocarbons that formed posted prices. Other quality crude oils are traded with from plants and animals that lived millions of years ago. Crude reference to benchmark crude oils and the pricing is oil exists in a liquid form in underground pools or reservoirs, adjusted using agreed-upon typically price differentials that take into account such factors as API gravity, sulfur content, and transportation costs – e.g., from produc - Density of an Oil (API Gravity) and areas tion to refineries. WTI oil Brent are two major benchmark crude oils with WTI used in the U.S. and Brent The density, or “weight,” of an oil is one of the largest used in global trade. A third major benchmark, Dubai, is determinants of its market value (another key character - mostly used in Asian trade. is sulfur content – see or istic text Sour?”). “Sweet box, The density of an oil is often referred to as “light” or pro Different countries, regions, - and geological formations “heavy” and is measured using API gravity. API gravity specific the using which determined is oil, an of gravity crude, of types different duce described generally are which is the ratio of its density to that of water (density of the as light or heavy, depending on their viscosity, and sweet or degrees oil/density of water) at 60 are Fahrenheit. Oils sour, depending on their sulfur content. As a rule, heavy oils generally classified as: are sour as they contain more sulfur. West Texas Intermediate (WTI), the U.S. pricing benchmark, is a light, sweet oil deliv- Light – API > 31.1 Medium – API between 22.3 and 31.1 ered at Cushing, Oklahoma. The Brent oil benchmark, also a – – API < 22.3 Extra Heavy API < 10.0 Heavy light, sweet oil, is a basket of North Sea oils used to set crude oil and petroleum prices around the world. By contrast, Mexi - However, specific oils may be categorized differently de - co’s Maya crude is both heavy and high in sulfur (sour). pending on the region where they are produced and how the oil is referred to by commodity traders. Crude oils that are light and sweet usually command higher prices than heavy, sour crude oils. This is partly because gas - number, unitless a is gravity specific Though gravity API oline typically which fuel, diesel - pre significant a at sell and values in practice are often referred to as degrees. The heavier products produced in to the refining mium process, API gravity of West Texas Intermediate is said to be 39.6 are more easily and cheaply produced using light, sweet crude degrees. API gravity moves inversely to density, which oil. Processing the light, sweet grades require far less sophis - means the denser an oil the lower its API gravity. An API and ticated energy-intensive refining processes. of 10 is equivalent to water, which means oils with an API will API an with oils while below water on float 10 above 10 will sink. | C egulatory r nergy ommission ederal F e Energy Primer 104

111 Density and Sulfur Content of Selected Crude Oils 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 per- cent sulfur. Sweet crude is easier and refine and safer to extract to transport than sour crude. Because sulfur is corrosive, sweet crude also causes less equipment damage to re- over fineries and thus results in lower maintenance costs time. Due to these factors, sweet crude commands a price premium over sour. Major sources of sweet crude include the Appalachian Ba- Source: Derived from EIA data sin 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 in - U.S. Crude Oil Supply cluding Indonesia. Sour crude oil has greater than 0.5 percent sulfur and some In 2014, the U.S. consumed approximately 16 million barrels for of this will be in the form of hydrogen sulfide, known per day (MMbd) of crude oil, of which 54 percent was pro- considered is sulfide Hydrogen smell. an its “rotten egg” duced domestically, a reversal from recent years when im- sour industrial hazard and, thus, stabilized crude has to be ports made up the majority of the supply. Between 1994 and via - transport be removal of hydrogen sulfide before it can 2013, the U.S. imported most of its crude oil. Imports peaked ed by oil tankers. in 2006 at 10.1 MMbd, or 67 percent of total supply. Sour crude is more common in the Gulf of Mexico, Mexi - co, South America, and Canada. Crude produced by OPEC U.S. Crude Oil Supply – Increased Production Member Nations also tends to be relatively sour, with an Displaces Imports 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 drilling production, horizontal high-pressure hydraulic and fracturing (fracking). T o date, the most prolific example of success in this technology is in the Bakken Shale in North Da - kota. Between 1990 and 2005, production in North Dakota averaged 89,000 barrels per day (Mbd). Production began - apply horizon to grow in 2006, as companies started to the tal 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. Source: Derived from EIA data | Energy Primer 105

112 shore deposits is more technically challenging and costly than In addition to North Dakota, other major producing locations th e U.S. includ e T exas, offsho re locations in in Gulf of Mex - on-shore, and over the past few years producers have opted the - to shift investments to the shale formations. ico, California, Oklahoma, and Alaska. Texas, the largest pro ducing state, also experienced a substantial increase in output Imports are also an important component to U.S. crude oil with the application of the new technologies. Texas onshore supply, accounting for 46 percent of U.S. supply, or 7.3 MMbd production fell steadily between 1980 and 2007, when it aver - in 2014 (excluding petroleum products). The largest foreign aged However, production began to up as ramp 1.1 MMbd. - supplier of crude oil (excluding petroleum products) is Cana companies targeted oil rich shale formations, including the da, which in 2014 accounted for 2.9 MMbd or almost 47 per- Eagle Ford Shale and the Permian Basin. Production in the cent of total imports. In Canada, unconventional oil produc - Permian Basin, one of the oldest oil producing formations in tion methods have resulted in robust production from the oil Texas, had been in decline prior to the implementation of the sands region in Alberta. The second largest supplier was Saudi new extraction techniques. By 2014, Texas production had enezuela, 1.2 V Mexico, by followed MMbd, and Arabia, with reached 3.2 MMbd. Iraq. One important attribute of rising crude oil production from Top Ten Foreign Suppliers of Crude Oil to the U.S. shale is that the majority of the output consists of light, sweet in 2014 oil. Approximately 90 percent of the nearly 3.0 MMbd growth in production from 2011 to 2014 consisted of light, sweet it as important is This grades. refinery invest - determine helps and operations and, thu s, influences the types of crude ments that are imported and processed oil in U.S. refineries. Top Five U.S. Crude Oil Producing Locations Source: Derived from EIA data Petroleum Reserves Source: Derived from EIA data At the end of 2014, there were an estimated 1,700 billion bar - rels of proved reserves in the world. The U.S. accounted for sufficient th is That reserves. ese or 49 of percent 2.9 billion, in the Gulf of production Offshore Mexico averaged 1.4 MMbd to last approximately 53 years at current production levels, it However, 2014. in peaked in - 2003 and has remained rela according to BP’s (June “Statistical Review of World Energy” for - from oil crude Producing years. 15 past the off flat tively | C egulatory r nergy ommission ederal F e Energy Primer 106

113 Proved Oil Reserves 10 countries in proved reserves, seven are members of the Or- Proved 2015). fluc - reserves Estimated quantities of oil tuate as new geological of Petroleum ganization Expor ting Countries (OPEC), - inter an that analysis of geologic and oil-producing This countries. of organization governmental supply sources are discov - engineering data demon - geopolitical and geographic concentration is an important ered, as the technology to strates with reasonable produce from known sour- factor as will be discussed later in this chapter. certainty are recoverable ces advances, and as price under existing economic and fluctuations change the operating conditions. economics of particular re- Crude Oil Refining sources. For example, the of increased Brazil offshore the deposits oil pre-salt discovery As of January 1, 2012, the U.S. had more than 17.3 MMbd of global proved reserves by adding a new potential source of capacity. For historica l reasons refinery dating back to gaso - water production. The advances in horizontal drilling and slick line five into divided is U.S. the II, ar W orld W during ning ratio technology fracturing in the size increased of proved reserves geographical regions called Petroleum Administration for De - the U.S. and other countries by making shale oil technically re- fense Districts, or PADDs. Approximately 44 percent, or 7.7 coverable. Proven reserves also increased when crude oil con - MMbd Coast, Gulf the along located is capacity, refining of in traded sistently above $100/barrel between 2008 and 2014, as PADD 3. the high prices made drilling in high cost areas economic. Petroleum Administration for Defense Districts In 2014 Most of the World’s Proved Oil Reserves were in the Middle East Source: EIA are refineries modern more and largest the of Most situated along the coast of Texas, Louisiana, Mississippi, and Alabama. crude traditional the to close located are refineries Many oil Source: Derived from BP Statistical Review of World Energy 2015 data production or import centers in the Gulf Coast or near major is products refined demand where ters cen population for greatest, including California and the areas near Philadelphia, Although two of the top three countries by proved reserved New York City, and Chicago. proven the of most Canada, and enezuela V are world’s - re processing general, crude oil refining involves crude oil In serves are in the Middle East. Five countries, Saudi Arabia, through distillation facilities where the crude oil is heated and Kuwait, Iraq, Iran, together Emirates, Arab United the and separated into its lighter and heavier components. The heat hold 46 percent of all proved reserves. In addition, of the top | Energy Primer 107

114 The growth in production of light, sweet oil from shale is Continental U.S. Refineries – Top 50 by Capacity changing the makeup in the types of crude processed at U.S. pro oil crude U.S. domestic when 1990s the During refineries. - along Coast Gulf the refineries spent declining, was duction - bil their operations and equipment reconfigure to dollars of lions to handle imports of heavy, sour crude oil from Mexico and Despite Venezuela. 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 Source: Derived from EIA data reach crude oi l to significantly the Gulf Coast refining centers, reducing the need for imports of light crude. Since Septem - causes the lighter, more volatile molecules to rise and, as they ber 2012, imports of light, sweet crude oil to the Gulf Coast cool, the heavier components such as heavy fuels and residual been regularly have Gulf Similarly, bbl/d. 200,000 than less fuels settle into trays and are carried out of the unit into their Coast imports of light, sour crude also declined and have been own processing streams. The lighter molecules rise higher in since bbl/d 200,000 July than less 2013. - the unit and are processed into light products such as gaso line the and naphtha. Depending on refinery configuration, heavier components may be further processed to yield higher amounts of the more valuable light products. Breaking down Imports of Crude Oil into the U.S. Gulf Coast the heavier products into lighter ones requires more special - ized and expensive catalytic as such processes and equipment crackers and cokers. Basic Crude Oil Distillation Unit & Product Output Source: Derived from EIA data Source: Derived from EIA data | C egulatory r nergy e ederal F ommission Energy Primer 108

115 FERC’s jurisdictional responsibilities regarding crude oil and Crude Oil and Petroleum Products petroleum product pipelines include: Transportation • Regulation of rates and practices of oil pipeline companies engaged in interstate transportation There are more than 190,000 miles of petroleum pipelines - Ensuring the furnishing of pipeline transportation to ship • in the U.S. Because of increased shale production, crude oil pers on a non-discriminatory and non-preferential basis pipeline mileage grew 8,174 miles or 15.5 percent between • Establishment of just and reasonable rates for transport - 2009 and 2013. Crude pipelines move oil from the production ing crude oil and petroleum products by pipeline fields for processing into terminals to refineries and import dynamics years, specifi - Changes in U.S. production in recent various products. Products pipelines then distribute the fuels - cally the growth of crude oil production in areas not tradition to various parts of the country. - ally served by oil pipelines, such as the Bakken Shale forma Colonial Pipeline Company is the largest pipeline in the U.S.; tion in North Dakota, have taxed the current pipeline system. transporting 844 billion barrel-miles (one barrel transported As a result, the country has experienced a sharp increase in one mile) of petroleum products in 2014. It is one of the most transportation of crude oil by rail, despite the fact that pipe - important products pipelines in the country as it carries supply line transportation is more economic than rail. An advantage exas T the refining centers in the ma - to Louisiana from and of rail transportation, however, is that companies can ramp- jor demand centers along the U.S. east coast. It transports capacity up - de and origin in flexibility more have and quickly approximately 100 million gallons per day of gasoline, diesel livery points. The largest oil-by-rail movements have originat - Lin to exas T Houston, from other and fuel, jet fuel, - products P from ed in specifically more 2014, In Dakota. 2, North ADD den, New Jersey on a 5,500-mile network, crossing 13 states. than 262,000 barrels, or 71 percent of all inter-PADD move - - The second largest pipeline, with 583 billion barrel-miles trans ment came from PADD 2. The majority of those barrels were ported in 2014 is Enbridge Energy. This pipeline begins in the ADD P Philadelphia the in refineries to shipped feed to likely 1, oil sands producing region in Alberta, Canada, and transports area. Additionally, approximately 50,000 barrels were import - 53 percent of the Canadian crude oil that comes into the U.S. ed or exported to Canada via rail. Once in the U.S., it moves the crude oil from North Dakota to Chicago and south into Cushing, Oklahoma. A distant third- Crude-by-Rail Volumes in the U.S. and Canada Keystone pipeline is the T ransCanada largest 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 diff erent pipeline from Keystone ransCanada T proposed the XL. Regulation of crude oil and petroleum product pipelines falls under a number of government entities. The Department of T ransportation’s (D OT) Pipeline and Hazardous Materials Safety Administ ration (PHMSA) is responsible for regulating and movement of hazardous ma - ensuring secure the safe and terials to industry and consumers by all modes of transporta - ensures Safety Pipeline of Office Its pipelines. luding inc tion, - safety in the design, construction, operation and mainte nance, and spill response of oil and natural gas pipelines and Source: Derived from EIA data pipelines. transportation liquid hazardous other | Energy Primer 109

116 allows for various types of exports including petroleum prod- The rise of oil-by-rail shipments has raised some safety issues, - ucts, exports of slightly ship refined crude oil condensate, as there have been a number of serious and, at times, fatal refinery affiliate ments of crude oil owned by a company to an incidents involving oil-laden rail cars. The U.S. Department of in Canada, and heavy-for-light crude oil swaps with Mexico. Transportation has worked with the rail and oil industry on U.S. exports of petroleum products rose substantially with new regulations involving car design and train operations. the increase of production of oil from shale. In 2000 the U.S. Two Federal statutes limit the movement of crude oil and This of exported 868,000 barrels finished products. number crude oil products. First, the Jones Act of 1916, 46 U.S. Code § had increased to 2.8 million barrels by 2014. generally foreign any prohibits built 55102, foreign-flagged or vessel from engaging in trade that begins at any point within the United States and delivers commercial cargo to any other Crude Oil and Petroleum Products - point within the United States. Because of the limited num Demand bers of oil and petroleum products vessels that meet the - Jones Act requirements, the ability to move crude oil and re The largest demand category marine ports is in products fined between supply. That short Prime Suppliers for petroleum products in means, for example, that producers are limited in their ability the U.S. is the transportation Companies that produce, to move crude oil to the Gulf Coast via pipeline and then ship it sector. Motor gasoline alone import, or transport refiners are limited to East Coast Coast Likewise, refiners. Gulf made up 56 percent of petro- products across State ability eir th in the up via refined Coast East move to products leum products sold by prime boundaries, to sell to local waterborne vessels. distributors, retailers, or suppliers into the U.S. market. end users. Prime supplier The second largest is No. 2 dis- U.S. Exports of Finished Petroleum Products sales are a good proxy for tillate, which made up 26 per- demand. cent of prime supplier sales in 2014, and which includes die- sel 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 per- cent of sales. All told, demand from the transportation sector accounts for approximately 90 percent of all petroleum prod- ucts consumed in the U.S. petroleum products Other lude: space for used propane inc heating and in petrochemical processes; kerosene used in heating and lighting; No. 1 fuel oil, which can be blended into Source: Derived from EIA data heating fuel or diesel fuel; No. 4 fuel oil used for commercial heating and power generation; residual fuels used in power A second statute, § 754.2 – Crude Oil, enacted during the 1970s generation and ship boilers; and asphalt used to build roads. oil crisis, requires licensing of U.S. crude oil exports. Although this statute is widely referred to as the oil export ban, it | e ommission r nergy egulatory ederal F C Energy Primer 110

117 Geopolitical and Economic Events Drive Crude Oil Gasoline and No. 2 Distillates Account For Most of the Petroleum Use in the U.S. Volatility Source: Derived from EIA data 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 Crude Oil and Petroleum Products Markets and Trading As a global commodity, crude oil’s price on the world markets is set by the traders who buy and sell the commodity. Al- Because of limited oceangoing transportation options, U.S. though crude oil trades at various locations around the world, - natural gas markets have historically been shielded from in - most trades are based on or derivative to a handful of bench ternational supply and demand developments. Crude oil and mark crude prices, such as WTI, Brent, and Dubai. There are petroleum products are traded globally, and their prices are also benchmarks for petroleum products, including New York and demand, geopolitical global by supply greatly influenc ed the in Harbor in (ARA) Amsterdam-Rotterdam-Antwerp U.S., and economic factors, and the policies of OPEC. Many of the Europe, and Singapore in Asia. countries in the top 10 oil suppliers to the U.S., such as Iraq, of a have enezuela, history and Russia, Kuwait, Colombia, V From 1987 through 2010, WTI and Brent traded within a few These factors can affect unrest political governance or issues. cents of each other, with WTI generally commanding a small production, reduce supply, and cause prices to rise. As a re- increase However, sharp and in price premium. the sudden - sult, world oil prices have experienced periods of great vola production of shale oil in the U.S. resulted in an oversupply at tility, driven by supply and demand fundamentals, external Cushing, causing WTI prices to drop below Brent. Between shocks, and speculative trading. 2011 and 2014, Brent commanded a premium, reaching as high as $27/barrel in premium September 2011. The Brent shrank in - a combina 2015, as world prices fell signifi cantly because of tion of lower demand, particularly from China, and growing supply from North America and other producers around the world. | Energy Primer 111

118 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 sup - ply and drive prices up, or increases to drive prices down. The - largest OPEC producer is Saudi Arabia. Other member coun Kuwait, the Libya, Qatar, enezuela, V Iraq, tries include Iran, 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 ac - counted for about 60 percent of the total petroleum traded internationally. The actions of OPEC, particularly in member can and do affect spare substantial capacity, countries with oil prices. | C egulatory r nergy ommission ederal F e Energy Primer 112

119 5. F arkEts and t rading m inancial markets affect physical natural gas and electricity in key ways. In the past decade, the commodity Financial markets markets associated with natural gas an d electricity expanded, both in terms of volumes traded and the types of products offered. One been result from this expansion has to alter the traditional re lationship between physical and financial markets. The traditional physical - view was that physical markets affect financial; financial products derive their value from relation products. T oday, the ship is bidirectional. Physical markets continue to affect financial markets markets, but now, financial markets can affect physical – including prices – as well. This chapter explores natural gas and electricity commodity Exchanges and capital markets. Trading on exchanges is subject to the rules of the exchange as well as laws and regulations. Exchange-traded contracts dardized, meaning th at specifications for the prod - are stan Financial Markets and Mechanisms uct’s quality, quantity, and location are established in advance by the exchange. Exchange rules typically permit bidirectional Financial markets are not physical locations like grocery stores trading, or the ability to buy or sell with equal ease. can go In to where experience the marketplace. financial - one Trading in exchanges is conducted through electronic plat - stead, they are an array of products, mechanisms, and partici - forms, websites on which traders can buy and sell, or through the out flesh together that pants marketplace. trading pits where traders actively call out orders to buy and physical As markets financial markets differ from mentioned, sell, known as open outcry. no physical delivery occurs. This does not mean finan - in that Natural gas and electricity are traded on commodity exchang - cial markets contain only investors and speculators; physical es such as the Nymex, the world’s largest physical commodity - market participants enter the financial market to hedge. Simi futures exchange. In addition to other commodities, including only con - financial markets involve that larly, it does not mean metals and agricultural products, Nymex facilitates the sale payout tracts that contain financial - instead of physical deliv and of products gas natural physical financial and purchase ery. Financial traders may use longer term physical contracts, - contracts. well as financial power as The ICE also offers nat but in a way that ensures no delivery will be required. Physical ural gas and electricity products, as well as emissions allow - often are markets financial and and closely use intertwined ances among a host of other commodities. Nodal Exchange the same market mechanisms. in participants to contracts futures (nodal) offers locational Consequently, markets financial understand to way good one Exchange markets. allows par - electricity Nodal the organized - is to look at the market participants, products, market mecha ticipants to trade electricity contracts for forward months, at nisms and trading that together constitute the market. RTO hubs, zones and nodes. Margin, or equity contributed as a percentage of the current Market Mechanisms market value of a commodity contract(s), allows market par- ticipants the ability to trade without having to pay cash for and con in both physical Transactions financial markets are - value full trades who someone the on Effectively, trade. the of ducted through exchanges or over-the-counter (OTC). In the margin borrows much of the money used to buy or sell from case of electricity, trades may also be conducted in regional the exchange or brokerage house. The trader posts collateral (RTOs 3). Chapter in addressed are organizations transmission | Energy Primer 113

120 by putting down a certain amount of money or percentage of Regional Transmission Organizations the trade value in cash or other items of value acceptable to Electricity is also bought and sold through RTOs. In general, the exchange. RTOs operate their markets to support the physical operation of the electric grid under their control, including making de- Over-the-Counter (OTC) Markets cisions about what generation to dispatch to meet customer OTC markets are any markets that are not exchanges or RTOs. demand. RTO markets are multilateral; buyers and sellers are are to be standardized but rather not required Transactions not matched individually against each other. RTOs allow for can range from complicated individual negotiations for one- bilateral physical transactions, although each RTO handles dard products traded through to stan contracts structured off settlement these although services, differently. provide RTOs - an electronic brokerage platform. The ability to tailor a con this by offered settlement the from differs exchanges. tract to the exact needs of the counterparties is one of the Also, RTOs use the word clearing to refer to the matching of chief contracts. benefits of OTC supply and demand – to clear the market means the RTO ac - OTC power contracts can be traded in either traditional or cepts - gen a If demand. meet to offers generation sufficient RTO power markets. erator’s it clears, market day-ahead that the in offer means the below or at offered was generation market clearing price OTC transactions are conducted through direct negotiations and was chosen to generate the next day. RTOs maintain between parties or through brokers. Brokers range from credit policies and allocate the costs of defaults or other per- voice brokers to electronic brokerage platforms. Unlike an formance failures across market participants. matches exchange, an electronic brokerage platform specific buyers and sellers, and is not anonymous. RTO markets may have elements that are similar in nature these transactions virtual financial is of to transactions. One Products may be negotiated individually or may be standard - (often referred to only as virtuals). For example, a trader may standardized with start contract, otiations neg any M ized. a market, day-ahead the generation offer in - genera the and such as the natural gas contract developed by the North tion does not show up in the real time market. As a result, the American Energy Standards Board (NAESB), and then modify is day-ahead the in offer generation market, his for paid trader it. Others start from scratch. Individually negotiated deals are - re on based day-ahead prices, but to effectively has to pay called structured contracts. Two commonly used contracts for place his power in the real-time market, paying the real-time electricity are the Edison Electric Institute (EEI) Master Pow - price. Financial participants can participate in virtuals; they er Purchase and Sale Agreement and the WSPP Agreement (generation physical in bids) product demand or offers use the (WSPP was formerly known as the Western Systems Power way in no physical delivery. results Virtuals are a financial that Pool). To be tradable, a contract must include terms and con - contracts, directly integrated into the RTO’s operation of its ditions that make it attractive to more than one entity. Con - demand, market; they affect physical supply and physical and sequently, plicated, one-off contracts negotiated to meet com prices. Virtuals are discussed further in Chapter 3. the need of an individual seller and buyer may have little or no dardized contracts traded on resale value. T ypically, the stan also - RTOs may offer financial pro transmission rights (FTRs) exchanges or electronic brokerage platforms are designed to grams, also discussed in Chapter 3. Typically, a transmission be of interest to many market participants. owner that turns over operation of its transmission to the RTO electricity flow to ability its over about and wants certainty In OTC markets, contracts are bilateral -- i.e., the process of the cost of transmission. Because the RTOs operate using negotiating the completion of a purchase or sale is between markets, this certainty cannot be provided directly. FTRs and the two market participants. similar instruments are designed to provide some degree of | C egulatory r nergy ommission ederal F e Energy Primer 114

121 sell compe nsation to these transmission owners and firm If financial product. physical the of price the influence otherwise or they succeed, benefits. rights holders. FTRs are linked to the physical operation of the position financial their RTO’s system in that the expected capacity of the transmis - - refers to the trading and volumes occurring in a mar Liquidity used sion is to determine the total capacity of FTRs offered. ket. A market is said to be liquid if trading and volumes are or firm rights hold - owners such that any trader can liquidate his position at any time, and transmission FTRs compensate the thin is market A prices. the affecting without so do ers in a couple of ways. First, the RTOs auction additional FTRs has it if in the market, including financial participants who to little others trading or volume; in these instances, trading may affect have no interest in buying, selling or transmitting physical prices. - prac justify to used often are liquidity of benefits The tices that increase trading or volumes. However, not all trad power. The proceeds of the auction are returned to some of - ing also auction The or holders. rights firm or owners transmission other volumes are uniformly beneficial to markets and - market dynamics need to be taken into account. determines a value for any FTRs held by the transmission own firm or ers sold; the and bought be can FTRs holders. rights Markets may not be uniformly liquid. For example, the mar - auction price gives an indication of their value for price dis- ket for the Nymex natural gas futures contract is generally covery. thought to be liquid. However, when the United States Natu - ral 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 mar affected. ket was is the total number of futures contracts in a de Open interest - livery month or market that has been entered into and not yet delivery. by transaction liquidated by an offsetting or fulfilled 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. Other Market Mechanisms and Concepts Clearing is transactions a process in which financial or physical are brought to a single entity, the clearing house, which steps Leverage or a control to position small benefit a of use the is into the middle of the transaction and becomes the counter - larger position. It increases the potential return, but also in- party to each buyer and seller. The clearing house assumes creases risk. Leverage can occur when a trader uses margin the risk that either the buyer or seller will fail to perform its to trade. - obligations. Generally, clearing is used to manage counterpar Leverage can be used in other ways. As discussed in Chapter ty risk. Clearing houses maintain rules about the creditworthi- 6, some traders may try to use leverage to manipulate the ness of traders, collateral that must be posted and, of course, market. For example, traders may use a smaller position in fees that must be paid for the service. position to benefit a physical larger market in the finan - the occurs at the end of a trading period, when the Settlement They may buy a financial product whose price is market. cial contract expires. At this time, delivery is to be made for a derived from a physical product. Then, they may try to buy or | Energy Primer 115

122 or a financial payout settled) contra physical (physically ct this may result in a margin call from the exchange or broker. contract (financially settled). Settlement made for a financial Mark-to-market is also an accounting transaction, in that a - occurs both in exchanges and in OTC trades. In OTC transac revalued reflect to company’s daily or trader’s accounts are tions, settlement occurs under the terms agreed upon by the changes in asset price. Losses can reduce the book value of a parties. On exchanges, settlement occurs in a documented its company creditworthiness. or trader, and can affect process and timeframe established by the exchange. is the buying and selling of contracts. Trades and Trading For example, every day at the close of Nymex trading, the nat - transactions are virtually synonymous. Both refer to the buy - gas futures contracts for fo rward months settle. The final ural ing and selling of power or natural gas. settlement for a given month occurs three business days prior to the start of the month of delivery (the prompt month). The Short selling is the selling of contracts a trader does not contract expires and the last-day settlement (LD settlement) buy will offsetting own, on the assumption that the trader is calculated based upon the trading in the last half-hour. LD contracts prior to the contracts’ expiration. This can be done final price for that particular futures contract settlement is the on an exchange or other market that allows for bidirectional - term. The last day for trading option contracts is the day be trading. Short selling has been of concern for potential market fore the futures contract expires. manipulation – traders sell a contract to drive the price down, and then buy when the price is low. Short selling is one of the Most market participants avoid trading during the settlement – they ways market participants can trade futures financially period. As the time to termination approaches, price risk and sell the future, then buy it before the contract expires so the volatility may increase, while market liquidity and the remain - contracts net out and the trader faces no delivery obligation. ing open positions (open interest) are decreasing. For the Ny - mex natural gas futures contract, most market participants A position is the net holdings of a participant in a market. A either liquidate or roll their open long or short positions well instrument specific a in purchas position combined - is trader’s before the settlement period. Rolling is the process of liqui - es and sales of that contract. A trader’s overall position is the dating the current month’s contract before it expires and pur - combination of all positions in all contracts the trader owns. chasing a comparable position in the upcoming month. The A trader’s position is often referred to as the trader’s commit - trader holds the same number of contracts, but the contract ment in the market. month held changes as time passes and contracts expire. - a position is the process of getting rid of a posi Liquidating Daily settlement prices are used to revalue traders’ position tion. A trader who owns a contract will sell it to liquidate it. - to the current market price, for accounting and for margin cal A trader who has sold a contract short will buy a contract to culations. Daily and LD settlement prices are also reported in liquidate it. After liquidation, the trader holds no contracts. publications and indexes, and are used for price discovery. have been imposed on ICE and Nymex ex- Position limits provides that at the end of each trad- Mark-to-market (MTM) accordance in specific ing changes to formulas, with accord ing day, all trading positions are revalued to current market regulations and proposed rules of the Commodity Futures in financial and accounting gains and loss - prices. This results Trading Commission. The position limits may restrict the num - es. Traders can remove money resulting from gains from their ber of shares a trader may hold in a particular investment at accounts or use them for further trading; they do not have to any point in time, during the month the contract expires, or liquidate their positions to get the money. Losses reduce the during some period closer to settlement. For example, the value of a trader’s position, and may reduce the amount of CME Group (CME) imposes accountability levels for any one collateral the trader needs to be able to trade on margin. If so, month and for all months, and has limits for expiration-month | C egulatory r nergy ommission ederal F e Energy Primer 116

123 Nymex Consequently, what traders buy and sell are contracts giving accountability for the CME’s Henry Hub nat - positions. them a right or obligation. For physical contracts, this is the ural gas futures contract are 12,000 contracts for all months, 6,000 contracts for one month and 1,000 contracts in the ex- obligation to deliver or take delivery of natural gas or electric- For is it contracts, financial payment. for exchange in ity piration month. Trading entities can petition to have these the waived or modified. right to a payout in exchange for payment, although the net time loss. net a to benefit net a over vary may value from - Volumes give an indication as to the nature of the activity oc rights traders give products curring in the market at any point in time. Volume can be ex- financial and physical Other to buy or sell a contract in the future at a given price – an option pressed in a number of ways. It can be the number of transac - volume period to buy or sell. tions executed during a specified of time or the of the product contained in the contracts. The word derivative is used for a category of contracts whose physical her ot some from derived is value - prod financial Volumes give market participants information about what is or going on in the market. For example, if many Nymex contracts uct or on trade contracts contract derivative Standardized . - are traded, and the number of trades is relatively few, mar exchanges such as Nymex. Financial contracts are derivatives. ket participants know that a relatively few traders are making Futures contracts are derivatives of the physical contract and high-volume trades. Conversely, if a high number of Nymex options on futures are derivatives of futures contracts. As contracts are traded and the number of trades is also high, futures contracts approach expiration, their price should, in then at least some of the trading is being done in small vol- theory, converge to spot prices – to derive their price from umes. This could result from broad interest in the market – futures contracts are However, at times, other prices. spot lots of active traders – or it can result from relatively few trad- simply the price parties are willing to pay for natural gas at ers making a lot of trades. some point in the future and may not derive their value from any other product or contract. Such expiring futures contracts Market Participants prices. may affect spot Financial markets are used by many types of participants. These markets present an opportunity for physical players, Instrument Basics - producers and marketers to buy or sell some physical prod own is identified its in market traded and is Each instrument - ucts or to hedge physical supplies and obligations with physi by the market name, such as spot or futures. Each market or fi nancial products. Investors, speculators and invest - cal - and instrument has characteristics such as timeframe, loca also ment fu nds use these for products financial and sical phy tion, contract type, product conveyed by the contract and, for financial gain. swaps, the mechanism for determining the payout. Products is what specifies Each Product conveyed : being con tract bought and sold. For physical contracts, this would be natural Products, for purposes of trading, are contracts — also gas or electricity. For derivatives, it may be a payout derived known as securities or instruments — that can be bought and from natural gas or electricity prices. All contracts conveying sold. Contracts for physical trading in natural gas or electricity or derived from natural gas, for example, would be in natural markets provide for the delivery of natural gas or electricity. gas markets. The actual molecules of gas or electrons may be delivered as a result of the contract. Financial contracts do not provide for Each : elements. time of trade number a has contract The Time delivery of a product; instead, provide a financial payout. they date is the date on which the contract is written (typically the date the trade is executed). | Energy Primer 117

124 - Monthly contracts are referred to by how close they are to ex The expiration day is the last day for a contract, after which piring. Spot month is the current month. Prompt month is the it is no longer available to be bought and sold; it is often the month after the spot month or current month – it is the next same day as the settlement day. Exchanges and electronic brokerage platforms may also impose a termination date, the trading month. For trading in January, February is the prompt last date on which a contract may be traded. month. Physical contracts also specify the delivery day(s) or month Another time element is the delivery or payout period, such – the day(s) or month during which the product is to be de- as daily, next day or monthly. Monthly contracts generally are for delivery in equal parts over a for livered. price specified a at month gas and for the contracted amount in each hour for power. For physical products, begin and end dates are the dates for : All physical contrac ts Location the location where which a physical product (natural gas or electricity) is to be specify Henry the delivered. For financial products, these dates address the con - delivered, to is gas ral natu the as such be in Hub tracts whose prices are used to set the payout. For example, Louisiana. Financial contracts also have a locational element, a next-day physical gas deal may have a trade date of Aug. 7, financial a if example, - For underlier. the by determined deriva a begin date of Aug. 8 and an end date of Aug. 8. A monthly tive uses the Nymex natural gas contract as its underlier, the derivative’s Hub. Henry the is element locational product may trade on Aug. 7, its trade date; the flow of natu - ral gas would have a begin date of Sept. 1 and an end date of For natural gas, the locations are referred to as market hubs, Sept. 30. which are located at the intersection of major pipeline systems. For the Nymex natural gas futures contract, the termination For power, contracts are often based on locations known as pricing and hub principal day and settlement day are the third-to-last business day of For hubs. or zones nodes, the gas, natural Nymex all for used is which gas Hub, Henry the is the month before the month in which the gas is to be deliv- point settlement The ered. to futures contracts and is the reference point for overall prices p.m. p.m. 2 from 2:30 occurs period on the termination day. in the United States. Prices for other locations are often refer - a the Henry Hub, known as from basis. as ences difference Short-term or spot contracts provide for delivery or payout Products traded on exchanges and preset products traded during the current or next day; the price for these contracts is - on OTC electronic brokerage platforms such as ICE use stan known as the spot price. pricing OTC dardized other Locations or locations points. for Daily physical contracts are for delivery on a given day or set transactions use whatever location the counterparties to the of days. contract desire. For physical contracts, the location must be can it products, financial For viable. the whatever physically be ical phys Electricity also specify financial contracts and may parties desire (although complicated locations make pricing or peak off-peak delivery, with the peak or off-peak hours de - the - dis price for points reference of lack to due difficult more contract. fined by the covery). Contracts for delivery a month or more into the future are for- amount specify the All of natural Quantity physical contracts : ward contracts, or if they are traded on exchanges, futures gas or electricity to be delivered. For contracts traded on an - contracts. The Nymex natural gas futures contract, for exam exchange or for preset contracts traded on an OTC electronic ple, provides for the delivery of 10,000 MMBtu of natural gas - brokerage platform, the quantity is predetermined and speci Contracts contract. the by specified month the in offered are OTC in traded contracts bilateral For - contract. mar fied in the for every month over the next 12 years. kets, the quantity contained in the contract can be anything | C egulatory r nergy ommission ederal F e Energy Primer 118

125 want parties be. For standardized products traded on the it to Physical Products is fixed. the brokerage quantity electronic platforms, for a contract is usually that set Price the : The by price paid Physical products involve an obligation to physically deliver. market and is usually known at the time the contract is bought Power product include energy, transmission s (firm - non and or sold. services. and ancillary firm) products Electric energy include spot transactions, full requirements sales and bundled ser - Fixed prices are known at the time the transaction is entered vices, among others. Natural gas products include the natural into – it is the price at which the seller agrees to sell and the gas molecules themselves, transportation and storage. buyer agrees to buy. Contracts sold at fixed prices are typically paid for at the time of purchase. Forward products are contracts for physical delivery in future months traded through the OTC market (including electronic Floating prices are set by formulas pegged to something brokerage platforms). If the product is traded on an exchange, whose price is not currently known but which will be known at it is known as a futures contract. 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 is futures contract traded a standardized forward A contract a location over the course of a month, typically as published in on a regulated exchange. Each contract represents the same an index. An index contract is a commonly traded instrument quantity and quality of the underlying physical commodity, val- - Chan Ship Houston the as based such points, trading major on ued in the same pricing format, to be delivered and received the Henry Hub. nel or at the same delivery location. In addition, the date of delivery and receipt is the same for all contracts traded for a particular is a cash market price for a physical commodity that Spot price calendar month. The only element of a futures contract that is is available for immediate (next day) delivery, and may be re- subject to change when it is bought or sold is the price. ported to publishers for indexes. For the natural gas industry, the dominant futures contract forward contracts and futures contracts are Standardized is the Nymex natural gas futures contract. For this contract, traded for every month, years into the future; the Nymex specifications the standard contract are the delivery location natural gas futures contract is traded more than eight years term the Louisiana; – Sabine Pipelin e Hub at the Henry Hub in into very the future although only the be first few years may – monthly; and the quantity – 10,000 MMBtu delivered equally liquid – i.e., actively traded. Each of those contracts for which over the course of the month. Not all forward contracts have trading has occurs has a price. Together, the prices for future fixed prices. Some involve trades executed now to buy or sell contract months creates a trajectory of prices known as for - at some point in the future, at a price to be set in the future. ward or futures curves. One example of this is a forward physical index contract. This - OTC contract obligates one party to buy the underlying com official reported The settlement price is effectively the final modity or security and the other party to sell it, for a delivery price for certain contracts and is an average of prices for a some at sets index specific price to be determined when trades occurring during the settlement period. For example, known date in the future. Many natural gas purchases are - the natural gas futures contract settlement price is made dur made under forward physical index contracts; among other ing the contract’s 30-minute settlement period – the last 30 things, it may provide state regulators with some assurance minutes of trading on the contract’s termination day. The that the price paid is reasonable. the payout for financial price settlement forms the basis for derivatives that use the contract as its underlier, as well as for tures be used Forward and fu contracts with fixed prices can margin calls and for reporting to index publishers. for price discovery, hedging or speculating. They may be | Energy Primer 119

126 East M-3 index (and would have to deliver it there). The trader traded by any of the participants listed earlier. Physical partici - physical earns the difference between the two contracts. A pants may use forwards or futures to obtain gas or electricity spread carries with it the obligation to make or take physi - - for delivery in some future month, or may use them to man cal delivery of natural gas at both points, so pipeline capacity age the risk of – or, hedge – their physical positions. Futures would be required to actually move gas between these points. contracts that go to delivery lose their anonymity at settle- less often, – fraction one small a only However, ment. than but trade, this execute also would could trader ial financ A percent – of futures contracts go to delivery. have to unwind both positions before delivery. - Indexes are formally published for both natural gas and pow er using a methodology posted by the publisher. An index the set to used be may settlement for of floating price price contracts. Indexes are also used by a variety of market partici - pants to inform their decisions in the many steps in the elec- tricity 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 prod- is uct, but instead provide a financial payout. This often based or some of value the on financial product specified by physical con tract, ca lled the underlier. The value of these financial the for contracts futures sell financial or buy may s trader Financial from financial or physical the contracts is derived value of the purposes, as exchanges have bidirectional trading – markets as instrument specified in the contract as the basis for payout; - in which trader can buy and sell contracts with equal ease. Bi such, they are derivatives. directional trading allows the sale of contracts a trader does buy a for - known as short own, not sales. A financial trade may is physical no have they that products financial of benefit key A neutralize ward or future, then either sell the contract later or delivery and they are self-liquidating. Speculators who trade the offset, it by obtaining an offsetting co ntract. Because two futures have to undo their position to eliminate the delivery the trader has no physical delivery obligation. Most Nymex obligation. One who trades derivatives, on the other hand, natural gas futures contracts do not go to delivery. does not bear the complications of unwinding positions; the individual can simply wait for expiration and receive or pay the combined be can products Physical physi - create to different contract’s payout. trading. use in physical and financial A price cal positions for spread can be created using forwards priced at indexes for Swaps The trader would buy physical natural gas two different hubs. at one index and sell at another. For example, the trader buys A key financial contract structure - used in natural gas and elec the Houston Ship Channel index (and would have priced gas at contract or swap, the swap A differences. for tricity markets is to take delivery of the gas there) and sells gas at the Texas is an exchange of one asset or liability for a similar asset or | C egulatory r nergy ommission ederal F e Energy Primer 120

127 Finally, traders may use options to boost their trading income liability. It may entail buying on the spot market and simulta - or to reduce the volatility of their returns. Options require less neously selling it forward. Swaps also may involve exchanging may include calendar spreads or basis income money up-front than a futures contract or swap, which can be flows. Swaps which of time reflect or locational price spreads expectations funds. limited with traders to benefit a variances. Physical instruments cannot be swaps because parties to physical goods pay or receive money in exchange for of delivery of the physical good. However, the exchange Trading and Transacting money in terms of payment and payout constitutes a swap. Trading Mechanics Options Market prices are the collective result of individual trades. An options contract conveys a right (but not the obligation) Open interest is the aggregation of traders’ positions. forms: the right else. so sell or buy to It comes in two mething specified price at or to buy or the right to sell something at a Trading is the buying and selling of contracts. A trade is a sin - The – before a specified date. option buyer buys the the right gle purchase or sale. A position is the accumulated unexpired - – to buy or sell in the future; the seller (or writer) sells the ob contracts purchased or sold, at a point in time. Traders may ligation to sell or buy if the buyer exercises his right. have positions in each contract, as well as an overall position all their contracts. reflecting 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 Trading requires a buyer and a seller, each willing to transact simply as the option’s price. The price at which the option may for a price. A buyer bids a price he or she is willing to pay to be exercised is the strike price. Electing to buy or sell the un - A price. bid the is this ract; cont a purchase - prod a seller offers - derlying commodity or security is known as exercising the op uct for sale; the price at offer which the seller offers it is the tion. price. Options traded on exchange or electronic trading platforms prices differ, they These may or may not be the same. When may be traded up to their expiration. Consequently, the own - them bid-ask the distance between spread. is the bid-offer or er of an option may sell it rather than exercise the option or This spread at price highest the between difference the is let it expire. - which buyers are currently willing to buy (the highest bid) ver sus the lowest price at which sellers are currently willing to Traders buy and sell options for a number of reasons. First, (the the and $7 bids buyer a if example, For offer). lowest sell they provide a risk management tool akin to insurance. Sec- offers seller at $3. is spread $10, bid-ask the ond, traders may use options traded on exchanges or electron- ic trading platforms to speculate. For example, a speculator Trading Concepts may trade an option and hope to gain from price movements, Traders need to know how their trades and positions will be akin to how they might trade other contracts, such as futures. market by affected - con by is done is this way One changes. If a trader buys an option, the trader can sell it up to expiration loses or benefits position or trade a er wheth when sidering the and the difference between pocket purchase price and - prices g o in or down. A position is long if it benefits from up the sales price. Further, as in futures, the seller of an option benefits it if short it is If prices. falling from creases in price. It can traded on an exchange - offset his obligation by purchas in fall a nor rise a ther nei it prices, is neutral, bene fitting from of the offsetting the ing risk the eliminating thereby option, be flat. to is said contract going to delivery. | Energy Primer 121

128 For example, a trader who purchases a Nymex natural gas fu- their support to flow cash predictable a need may financing. - contract is going LDCs may be concerned with state regulators determining in tures from benefit will contract that long; creases in price. A trader who sells the contract is going short; that their gas purchasing practices were imprudent. trader will benefit from the falling prices. Such concerns drive both procurement and sales decisions as well as risk management decisions. The two are often closely The concept of being long or short applies to other forms of transactions. Absent anything else, a generator is long elec- interconnected. For example, an LDC needs to buy enough tricity; a consumer short electricity. If the generator obtains a gas to meet extremely variable retail demand, but not too - much. An LDC also wants a price that regulators and consum - contract to sell electricity to the consumer at its cost of gener the generator is flat. ating, ers will see as reasonable. Consequently, LDCs usually develop a procurement and risk management – hedging – strategy tak - - The task of identifying long or short is not always easy. A trad ing these factors into account. er may have a variety of positions in a number of contracts, some long benefits position overall the How short. some and 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 accom to sell any of three objectives: plish buy or physical products, such as natural gas or electricity; to manage the risk of their physical positions, or hedge; or to make money. Hedging - portfo a create To purchase may sufficient quantitie s, an LD C Market participants with physical positions are in the market meet to with supply firm of block a supplies, minimum of lio to buy - profit enhance to electricity and gas natural sell and daily needs. An LDC trader may also decide to buy in the spot ability of their physical operations. These physical operations market to meet demand peaks. An LDC may diversify the determine their individual risks and hedging needs, and each sources of gas, both to improve reliability of supply but also physical market participant has a risk position related to its to diversify its price. business role in the physical delivery and consumption of nat - natural gas producer has different ural gas and electricity. A C may also manage LD risk financially. In the commodities An an LD C risks and therefore different hedging objectives than and securities markets, a hedge is a transaction entered into that needs to purchase gas to resell to retail consumers. for the purpose of protecting the value of the commodity or price from mo - vement by entering into an off adverse security sufficient An LD C, for example, is concerned with obtaining setting position in a related Hedging commodity or security. volumes to serve variable customer demand and in the price is used when describing the purpose of entering into a trans - paid for those volumes. A producer may be concerned about intent of offse tting risk from another related action with the selling all output (unless the output may be stored), and transaction. about the revenues obtained from the gas sale. Physical mar- ket participants may have other concerns as well. Producers | C egulatory r nergy e ederal F ommission Energy Primer 122

129 Speculation Capital Markets make money fall into a to of categories: Traders seeking couple investors and speculators. These categories are distinguished Capital markets provide the money to make investments in they use to profit from the by market. Investors the strategies infrastructure such as power plants or natural gas pipelines, they are in the market to benefit from are relatively passive; to operate plants and companies and to trade or conduct - long-term price movements and to diversify a broader portfo transactions. Access to capital depends both on the health lio. Speculators actively seek to gain from price movements. of capital markets and also on the perceived riskiness of the entity seeking the capital. To measure relative riskiness, many Trading Analysis different - cred including at measures, providers of capital look In deciding whether to trade, both hedgers and speculators firms: by assigned ratings it rating crediting major three the pay attention to what is going on in the market, and develop Standard and Poor’s (S&P), Moody’s and Fitch. their own view of where the market is likely to go. They may develop complicated forecasts as the basis for decisions on a Capital Expenditures to where and when er, wheth transactions: of number a build capi energy on have markets capital effect One in is markets - merchant power plant, how to hedge natural gas production, tal spending – undertaking work or investments that require and of course, when to buy and sell in the markets. capital. The 2009 recession and shake-up in capital markets commitments took a toll on capital spending as financial to thinking when analyz - Two general schools influence traders’ spending has infrastructure fell for the first time in years, but markets for trading opportunities. The first is fundamental ing been rising since 2011 (see bar chart). analysis, which takes into account physical demand and sup - ply fundamentals including production, pipeline and transmis - sion capacity, planned and unplanned outages, weather and economic and demographic changes. Changes in information - about fundamentals (or changes in perceptions of fundamen tals) 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 fore- casts price movements based on patterns of price changes, rates of change, changes in trading volumes and open inter- Source: Energy SNL est, without regard to the underlying fundamental conditions. Instead of looking at the market for a physical good, technical - The electric industry makes up the bulk of the capital expen analysis looks at trading and price changes. These quantitative ditures expected by energy companies. The majority of the methods have become a dominant part of market analysis. electric industry’s spending has been on electric transmission Technical analysis is used most often to determine short-term & distribution and generation. movements and trends, helping traders time their buys and sells. Types of Capital debt – comes from two general sources of financing Capital and equity. | Energy Primer 123

130 uity money from venture capital firms Debt financing involves borrowing money to be repaid over or private invest - – fixed or variable interest rate. at time, along with interest ment companies that buy into a company and which may a or may not take an active role in operating the company. With debt, the investor does not become an owner of the • - The most common form of stock is common stock, which company. Some common types of debt include bonds – secu with maturities rities - does not require regular payments, but it may receive divi markets in issue companies that financial dends; investor-owned utilities typically pay dividends. (when the loan has to be repaid) of more than a year; shorter and • term Equity does not provide a tax deduction to the company; issued by companies through financial markets; debt dividends and other payouts are not tax deductible. bank loans, such as lines of credit. A revolving line of credit is Stockholders and private equity investors get a say in how • an assurance from a bank or other institution that a company the company is operated and may impose restrictions. may borrow and repay funds up to some limit at any time. Mu - • Equity investors may be more willing to assume higher nicipal and cooperative utilities typically use debt; they have no ownership to sell. risks in return for a higher potential returns. Utilities are - typically considered fairly conservative investments. Natu include: debt of Characteristics ral gas producers attract a more risk-inclined investor. must be repaid or refi - • Capital obtained through debt • The return required to attract equity is higher than the nanced. interest paid to debt holders. • Debt may be short-term, such as lines of credit from banks • Equity capital does not require collateral; it gets a share in or corporate paper, or it may be long-term. the company. - • Companies must make their interest payments and repay Additional equity capital infusions may dilute, or reduce, • ment on schedule, or the debt holders can take action, the value of existing shares. - including forcing the company into bankruptcy. A com type Companies the with financing of the match to try often pany must generate sufficient cash through its operations investment they are making. Pipelines, power plants and payments. or through other financing to make these transmission facilities are long-lived assets. They are typically Interest gets paid before equity dividends. • stock as long-term and long-term using financed capital, such • Interest payments are tax deductible. bonds, which can have 30-year maturities. - • Debt gives lenders little or no control of the company (un less trouble). it gets into financial can leverage company profits; similarly, it can mag - • Debt nify losses. to Lenders are typically conservative, wanting • 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 perhaps operations, s company’ from benefit to through the dividends. • Equity capital can be kept by the company indefinitely. • Companies can issue shares in the company – stock – eq financial through - private use also may They markets. | C egulatory r nergy ommission ederal F e Energy Primer 124

131 that least at receive which but affiliated are half their cash Other capital is needed to conduct day-to-day operations. flow power Some of the cash needed to fund operations comes from a companies affiliated The sales. competitive from not typically have higher ratings; S&P views the integrated mer- come always company’s do revenues However, revenues. chants’ satisfactory. in when payments are due. Consequently, companies also rely or strong as scores S&P profile business on working capital. This can include some long-term capital typically rates IPPs fair or weak. from stocks and medium- and long-term bonds. Short term - The midstream sector of the natural gas industry, which con investments and day-to-day operations also rely on commer - tains pipelines, processing plants and storage facilities, is also cial paper and bank loans to cover day-to-day cash needs. If a typically rated investment grade. Midstream companies’ rat- issue to have may problems, significant faces company - es it ings average BBB and are said by rating agencies to have a – bonds junk – debt high-priced pecially financing. to obtain stable outlook. These are bonds issued by entities lacking investment grade credit ratings (see below). In the past few years, marketers and fina ncial ins titutions have taken an interest in the energy industry, and - financ equity of source another provided have ing. Credit Ratings Not all companies (or governments) present the same riski- ness to investors. Investors, traders and others consider the risks their counterparty may present, including the risk of default. One standardized too l used to relative risk is assess 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. organizat ions, including RTOs, Many ratings, bond consider 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 rat- own its way cy agen ing the in reflected risk, assessing of has rating system they use. Ratings by Industry Sector Electric utilities largely are rated investment grade, with rat- ings of BBB or better. Merchant generators include generating companies that are utilities (and are integrated with unaffiliated pletely com known as independent power producers, or IPPs) and those | Energy Primer 125

132 | C egulatory F ederal ommission e nergy r Energy Primer 126

133 6. m aniPulation m arkEt Following the energy crisis in the western United States early last decade, Congress enacted the Energy Policy Act of 2005 (EPAct U.S.C. § 824v (2012), and the Natural Gas Act, 15 2005), which added anti-manipulation provisions to the Federal Power Act, 16 U.S.C. § 717c-1 (2012). To implement these anti-manipulation provisions, the Commission issued Order No. 670, adopting the Com- 18 Anti-Manipulation Rule, which has been codified as (2014). C.F.R. § 1c mission’s 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 extends to situations where an entity has either voluntarily or Commission has interpreted to mean any person or form of - informa provided directive Commission or tariff a to pursuant - organization, regardless of tion but then misrepresents or omits a material fact such that its legal status, function or activi - a fraudulent device, scheme or ar using ties, and prohibits (1) the information provided is materially misleading. or statement untrue making or tifice, of a material fact any To violate the Anti-Manipulation Rule, one must also act with - omitting to state a material fact necessary to make a state a of sufficient state mind, that is, level of intent. Intentional ment that was made not misleading, or engaging in any act, conduct or recklessness (known as scienter) is enough to sat - practice or course of business that operates or would operate isfy the Rule. as a fraud or deceit upon any entity; (2) with the requisite sci- enter (that is, an intentional or reckless state of mind); (3) in The Commission also stated that for conduct to violate the “in connection with a transaction subject to FERC jurisdiction. The - connection with” element of the Rule, there must be a suf Commission need not show reliance, loss causation, or dam- - ju a and conduct fraudulent ’s entity an between ficient exus n ages to prove a violation. risdictional transaction. In committing fraud, the entity must to have intended recklessly to affect, acted affect, or have a - The prohibition is intended to deter or punish fraud in whole jurisdictional transaction. fraud energy sale markets. general in The defines Commission terms, meaning that fraud includes any action, transaction or conspiracy for the purpose of impairing, obstructing or de- feating 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 Com - Rule 10b-5 in an effort to prevent (and where mission (SEC) affecting appropriate, remedy) fraud and the manipulation 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 omis arise - sions as or Commission or tariff a of result a only would der, Rule Anti-Manipulation the However, regulation. or rule | Energy Primer 127

134 Manipulators have grown more sophisticated with the ex- - Manipulation comes in many varieties. As a federal court of ap peals has stated in the context of commodities manipulation, panded use of derivative products, whose value is set by the “We think the test of manipulation must largely be a practical - price of transactions in a related product. Many of the ma of Office FERC’s from staff that schemes nipulative one... The methods and techniques of manipulation are lim- - Enforce has staff) nforcement ment prosecuted and ited only by the ingenuity of man.” Cargill, Inc. v. Hardin , 452 (E investigated are cross-product schemes in which an entity engages in price- 1154, 1163 (8th Cir. F.2d 1971). The Commission recognized this making trades in the physical market, often at a loss, with the reality by framing its Anti- Manipulation Rule broadly, rather price settlement the affect to intent articulating specific conduct that would violate its rules. derivative price-taking of than instruments. Cross-product manipulation is also referred to While manipulative techniques may be “limited only by the as related-position manipulation. Such trading can violate the ingenuity of man,” the following are broad categories of illus - Anti-Manipulation Rule because the trading is not undertaken trative manipulations that have surfaced in the securities and in response to supply-and-demand fundamentals but rather commodities markets (including the energy markets) over the categories these of borders could trading Such position. another to undertaken The is benefit some and flexible are years. be considered to undermine the functioning of jurisdictional can belong to multiple categories, such as wash trading (i.e., markets. buying and selling identical stocks or commodities at the same time and price, or without economic risk). Traders may also to understanding cross-product - manipulation is that fi Key manipula - combine elements of various schemes to effect a nancial and physical energy markets are interrelated: physical tion. natural gas or electric transactions can help set energy prices on which products manipulator a that so based, are financial can use physical trades (or other energy transactions that af- Manipulative Trading Techniques and to prices) physical fect his benefits that way a in prices move Cross-Product Manipulations looking overall financial useful way of position. at ma - One nipulation is that the physical transaction is a “tool” that is A number of manipulative trading techniques that have arisen used to “target” a physical price. For example, the physical in securities and commodities trading may be subject to the a scheduled flow power physical a be cou in tool ld ahead day Commission’s Anti-Manipulation Rule. Traders may seek to electricity market at a particular “node” and the target could trading volumes or trade at off-market prices to serve inflate be the day-ahead price established by the market operator for as maintaining market confidence in a compa - such purposes that node. Or the physical tool could be a purchase of natural - ny’s securities or to move a security’s price to trigger an op gas at a trading point located near a pipeline, and the target tion. Marking the close is a manipulative practice in which a could be a published index price corresponding to that trading trader executes a number of transactions near the close of a point. The purpose of using the tool to target a physical price trading to day’s the closing or settlement or contrac t’s affect is to raise or lower that price in a way that will increase the price. This may be done to obtain mark-to-market marks for value of a , Financial Transmission “benefiting position ” ( e.g. or s, call margin avoid to valuation, to benefit other positions Right or FTR product in power markets, a swap, a futures con - in related instruments. Banging the open is a similar practice tract, or other derivative). 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 value position benefiting the of the ing Usually, increas the is signal information on fundamentals. Other manipulative trad- goal or motive of the manipulative scheme. Understanding ing techniques exist, and practices like wash and round-trip the and benefiting financial manipulator’s a of scope nature are discussed in more detail that below fit under this trading positions—and how they relate to the physical positions— description as well. can be a key focus of manipulation cases. The Commission’s | C egulatory r nergy ommission ederal F e Energy Primer 128

135 trading Anti-Manipulation Rule is an intent-based rule: a finding of inflate falsely may it however, place; takes exchange manipulation requires proving that the manipulator intended volumes at a price level and give the impression of greater (or in some cases, acted recklessly) to move prices or other- trading activity. False reporting and wash trading have result- wise distort the proper functioning of the energy markets the ed in a number of criminal prosecutions by the Department of Commission regulates. A company can put on a large physical Justice. prices, of that market affect may that trade if the purpose but trade is to hedge risk or speculate based on market funda - mentals—rather than, for example, the intent to move prices Withholding to bene fit without conduct, position—this financial related a more, would not violate the Commission’s Anti-Manipulation Withholding is the removal of supply from the market and is Rule. 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 Information-Based Manipulations positions those back buy to price. inflated an at Many manipulative schemes rely on spreading false informa - Withholding played an important role in the western power tion, which involves knowingly disseminating untrue informa - crisis that engulfed California in 2000. Market participants, tion about an asset’s value in order to move its price. A well- particularly Enron, exploited supply-demand imbalances and known scheme is the pump and dump, in which a participant - poor market design. Generation operators scheduled mainte spreads a rumor that drives the price up and then sells the nance outages during peak demand periods, which is an ex- shares after the price rises. In the energy markets, a common ample of physical withholding. In addition, transmission lines way to misrepresent a commodity’s value is to misrepresent were overscheduled to create the appearance of congestion the price of the commodity or its level of trading activity. False to effort an in of result The electricity. of supply the reduce reporting and wash-trading schemes were well-documented withholding economic with efforts and combination in these information-based manipulations that took place in the early information-based schemes discussed above was that whole - 2000s and contributed to the western energy crisis. False re- sale & Gas Pacific electricity prices as soared. Utilities such a when occurs porting participant fictitious submits market Electric (PG&E) and Southern California Edison were unable - transactions or information to a price-index publisher to af to pass on these high prices to their retail customers because fect the index settlement price. Another form of informa - of state price caps. The crisis led to widespread blackouts, tion-based manipulation involves providing misinformation heavy losses to the state’s economy and the bankruptcy, in through conduct that is intended to misrepresent a market April 2001, of PG&E. participant’s characteristics, circumstances, or intentions, to receive order in payment, or award for which it a benefit, Economic withholding, which also contributed to the western - would not be eligible but for the misleading conduct. This in power crisis, is similar to physical withholding, but rather than cludes engaging in trading strategies that are intended to cre- or a stockpiling generator a off turning commodity, physical ate market results that are inconsistent with the purpose of that resource needed a for price offer an the manipulator sets the transactions. is so high that the resource will not be selected in the market. For example, a generator in a constrained market such as New but actual involve offsetting may trading wash Similarly, high that York City could purposely set its offer price enough trades for the same (possibly nonmarket) price and volume it would not be called on to run. This scheme would create a between the same market participants such that no economic shortage of generation and, thus, would raise prices for the | Energy Primer 129

136 generation benefit of the rest of its fleet or its financial posi - Court for the Eastern District of California on October 9, 2013. tions. As withho lding is intend ed to benefit a market partici - The matter is pending before that court. pant’s overall portfolio, it is similar to cross-product manipula - tion, discussed above. BP America, Inc. and Affiliates On August 5, 2013, the Commission issued an order to show 2 Representative Matters In that proceed- cause and notice of proposed penalty to BP. BP that alleged staff orcement Enf ing, uneconomic made The following representative matters involve at least one of took its increase to and Channel Ship Houston at sales steps the types of manipulative schemes described above. Each of - manipula a of part as Channel Ship Houston at share market these matters has either been resolved through settlement or Daily Gas Channel Ship Houston the suppress to eme sch tive is currently pending before a district court or administrative - index, and that this scheme was motivated by a desire to ben law judge. efit financ and ial positions held by BP sical phy certain whose price was set by the same index. In sum, as cross-product undertook BP that staff nforcement E manipulation, alleged Barclays Bank, PLC, Daniel Brin, Scott Chann Ship on at trades Houst intent the with – tool the – el Connelly, Karen Levine, and Ryan Smith alter to price index Daily Gas Channel Ship Houston the of the (Barclays and Traders) physical of value and the increase to – target the - financial On July 16, 2013, the Commission issued an order determin - the prices were set by index - positions whose the benefiting ing that Barclays and Traders violated the Commission’s Anti- positions. On May 15, 2014, the Commission set the matter for Manipulation Rule and assessed civil penalties of $435 million hearing to determine whether BP’s conduct violated the Anti- 1 3 - The Com against Barclays and $18 million against the Traders. Manipulation Rule. mission also ordered Barclays to disgorge $34.9 million plus interest Commission The profits. unjust in found that Barclays Constellation Energy Commodities Group and Traders engaged in loss-generating trading of next-day, to physical electricity on the ICE with fixed-price the intent - In 2012, the Commission approved a settlement with Constel position benefit financia l swap trading s at primary electricity lation Energy Commodities Group (CCG) in which CCG agreed points in the western United States. In sum, Barclays under- disgorge to penalty civil a pay and profits t unjus in million $110 - physical took fixed-price, Day-Ahead trades at various W est $135 alleged staff Enforcement million. had of en that CCG - ern trading points – tool – to intentionally change the ICE daily loss-generating significant day- virtual into physical tered and for the benefit – of its target financial swap posi - the – index ahead transactions in electricity markets in and around New index benefiting the – that on based was price whose tions York State with the intent to move day-ahead price settle- position. financial received their benefit to ments that positions swap prices from those settlements. - Barclays and Traders elected to challenge the penalty in feder district court, and Enforcement staff filed an al action to affirm the Commission’s assessment in the United States District merica Inc., BP A 2 61,100 (2013). 144 FERC ¶ , Karen Levine, and Barclays Bank PLC, Daniel Brin, Scott Connelly 1 BP America Inc., 3 147 FERC ¶ 61,130 (2014). - 144 FERC ¶ 61,041 (2013) (order assessing civil penal Ryan Smith, ties). | C egulatory r nergy e ederal F ommission Energy Primer 130

137 - the Commission issued Orders Assessing Civil Penalties to Lin Deutsche Bank Energy Trading subjects the that finding Silkman, and CES, coln, fraudulently (Deutsche Bank) repeatedly and baselines load inflated reductions load offered in the minimum offer price at order to maintain the inflated On January 22, 2013, the Commission approved a settlement 5 baseline. the Enforcement involved scheme staff that und fo between the Office of Enforcement and Deutsche Bank, in uneconomic energy purchases that served no legitimate pur- which Deutsche Bank agreed to disgorge $172,645 in unjust pose and were designed to increase DALRP payments that In profits and settlement, the million. $1.5 of penalty civil a pay would not have otherwise been obtained. The Commission staff concluded th at Deutsche violated the Enforcement Bank - determined that this scheme misled ISO-NE, inducing pay Commission’s Anti-Manipulation Rule, through cross-product the ments on based entities these for baselines to inflated manipulation in which it traded physical exports at Silver Peak load reductions that never occurred. that were not profitable with the intent to benefit its Con - gestion Revenue Rights (CRR) position. Deutsche Bank had a The Commission ordered Lincoln to pay $5 million in civil pen - CRR position at the 17-MW Silver Peak intertie that started to alties and approximately $379,000 in disgorgement; CES to lose money. To stem those losses, Deutsche Bank submitted pay $7.5 million in civil penalties and approximately $167,000 export bids to change the price at Silver Peak, as that price in disgorgement; and Silkman to pay $1.25 million in civil penal - CRR value of Deutsche Bank’s affected the position. By chang - ties. None of the respondents paid the amounts assessed by ing that price, Deutsche Bank diminished its losses on the CRR petitions two filed the in Commission. the staff Enforcement position. Deutsche Bank consistently lost money on its export United States District Court for the District of Massachusetts avoided the by offset were losses those but Peak, Silver at on 2, the of affirmance and review seeking 2013 December - losses on its CRR position. In sum, as cross-product manipula Commission’s orders. These petitions are pending. tion, Deutsche Bank traded physical exports – the tool – to alter the price at the Silver Peak – the target – to diminish its – the benefiting position. losses on its CRR 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 Commis The Anti-Man ipulation Rule. Office sion’s of Enforcement and Rumford settled the allegations against the company, which 4 the Commission approved in March 2013. On August 29, 2013, Lincoln Paper and Tissue, LLC, 5 144 FERC ¶ 61,162 (2013) (order as - 142 FERC ¶ 61,218 (2013) (order approving ord Paper Co., 4 Rumf sessing civil penalty); 144 FERC Competitive Energy Services, LLC, stipulation and consent agreement). ¶ 61,163 (2013) (order assessing civil penalty); Richard Silkman, 144 FERC ¶ 61,164 (2013) (order assessing civil penalty). | Energy Primer 131

138 JP Morgan Ventures Energy Corporation Louis Dreyfus Energy Services L.P. (JPMVEC) (Louis Dreyfus) On July 30, 2013, the Commission approved a settlement be- On February 7, 2014, the Commission approved a settlement Louis Enforcement, of Office Dreyfus, one tween the Office of Enforcement and JPMVEC resolving an the between and of its traders, Xu Cheng. 7 Under the terms of the settlement, 6 JPMVEC paid investigation of JPMVEC’s bidding practices. Louis Dreyfus agreed to disgorge $3,334,000 in unjust earn- $285 million in civil penalties, $124 million in disgorgement to ings, plus interest, and pay a civil penalty of $4,072,257. Cheng, CAISO ratepayers, and $1 million in disgorgement to MISO. In who had previously crafted and described the manipulative addition, the company agreed to waive its claims that CAISO - scheme in his doctoral dissertation, agreed to pay a civil pen owed it money from two of the strategies that Enforcement ex - In addition, Louis Dreyfus prohibited Cheng alty of $310,000. had investigated, and to conduct a comprehensive staff from virtual trading anywhere in the United States, and agreed ternal assessment of its policies and practices in the power that he would not be permitted to resume such trading for at business. least two years. the Enforcement staff determined that JPMVEC violated concluded Commission’s Anti-Manipulation Rule by engaging in twelve Louis that staff nt Enforceme settlement, the In Dreyfus violated the Commission’s Anti-Manipulation Rule manipulative bidding schemes in CAISO and MISO. These when it made certain virtual trades in MISO with the intent to schemes distorted a well-functioning market in several ways, - increase the value of its nearby FTR position. Louis Dreyfus es including but not limited to, misleading CAISO and MISO into tablished an FTR position near the Velva node. Louis Dreyfus paying JPMVEC at rates far above market prices; submitting at started it until position, FTR th on profit no or little earned bids that were expected to, and did, lose money at market place - rates, as they were not driven by the market forces of sup to virtual demand bids at the V elva node to benefit the ply and demand; defrauding the ISOs by obtaining payments FTR position. Louis Dreyfus consistently lost money on those was loss that on but bids, did JPMVEC that benefits for deliver; not and displacing other its on offset virtual demand gains generation its FTR position. In sum, as cross-product manipulation, Louis congestion and prices. energy influencing and Dreyfus submitted virtual demand bids – the tool – to alter the price at the Velva node – the target – to increase the value of the benefiting position. position FTR its – rading (Louis Dreyfus Energy Services), MISO Virtual and FTR T 7 146 6 In Re Make- Whole Payments and Related Bidding Strategies, 144 FERC ¶ 61,072 (2014). FERC ¶ 61,068 (2013). | C egulatory r nergy e ederal F ommission Energy Primer 132

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