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Science and Economics

Basic Science

* “Energy,” as defined by the Oxford Dictionary of Biochemistry and Molecular Biology, is “the capacity of a system for doing work.”[1] [2] [3]

* Energy can take varying forms, such as thermal, electrical, mechanical, nuclear, chemical, gravitational, acoustic, and electromagnetic.[4]

* Two common measures of energy are British thermal units (Btu) and joules. All forms of energy can be expressed in these units. One Btu is the amount of energy needed to raise the temperature of one pound of water from 39 to 40 degrees Fahrenheit.[5] One joule is the amount of energy needed to lift one hundred grams (3.5 ounces) upward by one meter (3.3 feet) while on the surface of the earth.[6]

* As a consequence of the First Law of Thermodynamics, energy and matter cannot be created or destroyed; they can only be transformed from one form into another.[7] [8] [9] [10]

* As a consequence of the Second Law of Thermodynamics, when energy is transformed from one form to another, some of it disperses, thus making it less useful for performing work.[11] [12] [13] [14]


Practical Uses

* Humans have learned to harness energy to accomplish tasks such as transporting people and products, heating and cooling homes, farming, cooking, manufacturing goods, communicating across vast distances, and generating light.[15]

* The average annual energy consumption in the U.S. is 309,000,000 Btu per person. To generate this amount of energy through physical human effort (like pedaling bicycles to drive generators) would require 208 people working nonstop for a year.[16]

* “Embodied energy” refers to the energy used in making materials. For example, to make a common clay brick weighing 5 pounds requires about 5,386 Btu of energy. The materials of a typical house embody about 850 million Btu, which is equivalent to the energy that would be generated by 573 people pedaling bicycles nonstop for a year.[17]


Economic Impacts

* In 2013, energy expenditures in the U.S. were 8.3% of gross domestic product (GDP), or $1.4 trillion ($1,383,045,600,000).[18] In inflation-adjusted 2015 dollars,[19] this amounts to $4,446 for every U.S. resident or $11,491 per household.[20] [21]

Energy Spending as a Share of GDP

[22]

* The costs of most products are affected by the costs of energy, even products with low embodied energies because the costs of energy affect the costs of transporting products. Because energy costs influence the costs of products, higher energy costs tend to drive up unemployment, drive down wages, and cause other negative economic effects. Such consequences tend to be harsher in poorer nations.[23] [24] [25]

* Roughly one third of the world’s population does not have access to modern forms of energy. In these areas, people use biomass (primarily wood) for about 80% of their energy, and women and children spend an average of 9-12 hours a week collecting firewood. Per the Institute for Plasma Physics in the Netherlands:

Poor people spend a large part of their time collecting the energy they need. This time cannot be spent in producing things that can be sold, working on the land, or learning. This is called the poverty trap: once you are poor, it is very hard to get out of poverty again, because you need to spend all your time in survival activities. This normally leaves very little time to do things that might get you out of poverty, like education, or production of goods to sell on the market.[26] [27]

* Higher energy costs drive up the costs of food.[28] This has greater impacts on poorer nations and individuals because they spend a larger portion of their income on food.[29] [30] In Haiti during 2007 and 2008, higher energy prices contributed to increased food prices, driving Haiti’s poorer people to obtain nourishment from cookies made of mud.[31]

* Per the Congressional Research Service, “The economic well-being and economic security of the nation depends on having stable energy sources.”[32]

* Per the U.S. Government Accountability Office, “Americans’ daily lives, as well as the economic productivity of the United States, depend on the availability of energy….”[33]

* Per the textbook Introduction to Air Pollution Science, “The availability of affordable electric power is essential for public health and economic prosperity.”[34]

* Per the U.S. Energy Information Administration:

  • “Liquid fuels play a vital role in the U.S. energy system and economy, and access to affordable liquid fuels has contributed to the nation’s economic prosperity.”
  • “Cheaper energy allows the economy to expand further….”
  • “increasing energy production has immediate benefits for the economy.”[35] [36]

* Per the textbook Microeconomics for Today, countries with slower economic growth “are less able to satisfy basic needs for food, shelter, clothing, education, and health.”[37]


U.S. Energy Supplies

* During 2015:

  • petroleum supplied 36.2% of all primary energy consumed in the U.S.
  • natural gas supplied 29.0%.
  • coal supplied 16.1%.
  • nuclear supplied 8.5%.
  • hydroelectric supplied 2.4%.
  • biofuels supplied 2.2%.
  • wood supplied 2.1%.
  • wind supplied 1.9%.
  • solar supplied 0.5%.
  • biowaste supplied 0.5%.
  • geothermal supplied 0.2%.[38]
Sources of Primary Energy

[39]

* The following graphs show the components of U.S. energy consumption over time. The first graph shows consumption measured in BTUs. The rest show consumption measured as a portion of total U.S. energy consumption. Each succeeding graph uses a smaller scale to provide increasing resolution.

Primary Energy Consumption

[40] [41] [42]

Fossil Fuel and Nuclear Energy Consumption

[43]

Renewable Energy Consumption

[44]

Low-Production Renewable Energy Consumption

[45]

* Data from the graphs above:

Components of U.S. Energy Consumption

Source

1950

1960

1970

1980

1990

2000

2010

2015

Petroleum

38.5%

44.2%

43.5%

43.8%

39.7%

38.7%

36.4%

36.2%

Natural Gas

17.2%

27.5%

32.1%

25.9%

23.2%

24.1%

25.2%

29.0%

Coal

35.7%

21.8%

18.1%

19.8%

22.7%

22.8%

21.4%

16.1%

Nuclear

0.0%

0.0%

0.4%

3.5%

7.2%

8.0%

8.7%

8.5%

Hydroelectric

4.1%

3.6%

3.9%

3.7%

3.6%

2.8%

2.6%

2.4%

Biofuels

N/A

N/A

N/A

N/A

0.1%

0.2%

1.9%

2.2%

Wood

4.5%

2.9%

2.1%

3.2%

2.6%

2.3%

2.0%

2.1%

Wind

N/A

N/A

N/A

N/A

0.0%

0.1%

0.9%

1.9%

Biowaste

N/A

N/A

0.0%

0.0%

0.5%

0.5%

0.5%

0.5%

Geothermal

N/A

0.0%

0.0%

0.1%

0.2%

0.2%

0.2%

0.2%

Solar

N/A

N/A

N/A

N/A

0.1%

0.1%

0.1%

0.5%

[46]


Sectors & Electricity

* The U.S. Energy Information Administration (EIA) divides the energy market into four major sectors: residential,[47] commercial,[48] transportation,[49] and industrial.[50] [51]

* In 2014, the residential sector consumed 22% of all U.S. energy, the commercial sector consumed 18%, the transportation sector consumed 28%, and the industrial sector consumed 32%.[52]

* EIA sometimes classifies “electric power” as separate sector,[53] although the electricity produced by this sector is consumed by the four major sectors.[54]

* In 2014, the electric power sector consumed 39% of all U.S. energy.[55]

* Per the Institute for Plasma Physics in the Netherlands:

  • “Electricity is the most flexible form of energy: it can be used for virtually any application.”
  • Using electricity to generate heat “is normally much more expensive than using fossil fuels, and it is only used for relatively small amounts of heat.”
  • “Electricity is also quite hard to store in large quantities. You need large, heavy batteries to store a reasonable amount of electrical energy.”
  • “The central generation of electricity means it has to be distributed over the country in order to bring it to your house. This causes an average loss of energy of 10%, and needs a large and expensive distribution system.”[56]

* During 2015:

  • coal generated 33.2% of all electricity produced in the U.S.
  • natural gas generated 32.7%.
  • nuclear generated 19.5%.
  • hydroelectric generated 6.0%.
  • wind generated 4.7%.
  • wood generated 1.0%.
  • solar generated 0.9%.
  • petroleum generated 0.7%.
  • biomass (other than wood) generated 0.5%.
  • geothermal generated 0.4%.[57]
Sources of U.S. Electricity

[58]

* Economic growth is a key factor in the growth of electricity generation.[59]

* The following graphs show the components of U.S. electricity generation over time. The first graph shows generation measured in kilowatt hours. The rest show generation measured as a portion of total U.S. electricity generation. Each succeeding graph uses a smaller scale to provide increasing resolution.

U.S. Electricity Generation by Category

[60]

Electricity Generation by Major Source

[61]

Electricity Generation by Minor Source

[62]


Pollutants

* When modern energy is unavailable or expensive, people tend to burn more wood, crop waste, manure, and coal in open fires and simple home stoves. Open fires and home stoves do not burn fuel as efficiently as commercial energy technologies, and hence, they produce elevated levels of outdoor and indoor pollutants. The added consumption of wood also causes deforestation.[63] [64] [65] [66] [67]

* Assessing the full environmental impacts of different energy technologies requires looking beyond the effects at a single point of production, use, or disposal. To do this, researchers perform “life cycle assessments” or LCAs. Per the U.S. Environmental Protection Agency (EPA), LCAs allow for:

the estimation of the cumulative environmental impacts resulting from all stages in the product life cycle, often including impacts not considered in more traditional analyses (e.g., raw material extraction, material transportation, ultimate product disposal, etc.). By including the impacts throughout the product life cycle, LCA provides a comprehensive view of the environmental aspects of the product or process and a more accurate picture of the true environmental trade-offs in product and process selection.[68] [69]

* Per a 2008 paper in Environmental Science & Technology:

Indeed, all anthropogenic [manmade] means of generating energy, including solar electric, create pollutants when their entire life cycle is taken into account. Life-cycle emissions result from using fossil-fuel-based energy to produce the materials for solar cells, modules, and systems, as well as directly from smelting, production, and manufacturing facilities.[70]

* The air pollutants generated by energy sources vary with factors such as combustion methods, manufacturing techniques, and pollution control technologies.[71] [72] For example, bituminous coal combusted in a fluidized bed boiler without pollution controls produces one tenth the sulfur dioxide of the same fuel burned in a cyclone boiler without pollution controls.[73] [74] [75]

* In general:

  • electricity generated by nuclear, hydropower, solar, geothermal, and wind energy emits a fraction of the air pollutants of fossil fuels.[76] [77] [78] [79] [80]
  • geothermal heat pumps generate less pollutants than any other technology for heating and cooling.[81]
  • biofuels usually emit less air pollutants than petroleum-based fuels, although some biofuels emit more nitrogen oxides and volatile organic compounds over their lifecycles.[82] [83] [84] [85] [86]
  • natural gas combustion generates the lowest air pollutant emissions of all fossil fuels.[87] [88] [89] [90] [91]
  • as of 2000, electricity generated by coal combustion created more sulfur dioxide and nitrogen oxides than any other fuel.[92]

* Per the U.S. Department of Energy (2010):

While coal used to be a dirty fuel to burn, technology advances have helped to greatly improve air quality, especially in the last 20 years. Scientists have developed ways to capture the pollutants trapped in coal before they escape into the atmosphere. Today, technology can filter out 99 percent of the tiny particles and remove more than 95 percent of the acid rain pollutants in coal, and also help control mercury.[93] [94]

* In the U.S. from 1990 through 2015, sulfur dioxide (SO2) emissions per Btu of coal-generated energy decreased by 86%, and nitrogen oxides (NOx) emissions decreased by 78%.[95]

* Since the late 1970s, new automobiles have been equipped with catalytic converters, an “anti-pollution device” that converts “exhaust pollutants … to normal atmospheric gases such as nitrogen, carbon dioxide, and water.”[96] [97] [98]

* Facts about air pollution levels and their effects are detailed in Just Facts’ research on pollution.


Greenhouse Gases

* Carbon dioxide (CO2) contributes more to the greenhouse effect than any other gas released by human activity.[99] [100]

* In general:

  • electricity generated by nuclear, solar, geothermal, and wind energy emits a fraction of the greenhouse gases of fossil fuels.[101] [102] [103] [104] [105]
  • hydropower’s “air emissions are negligible because no fuels are burned. However, if a large amount of vegetation is growing along the riverbed when a dam is built, it can decay in the lake that is created, causing the buildup and release of methane, a potent greenhouse gas.”[106]
  • when extracting natural gas, coal, and petroleum from the ground, uncombusted methane can be released. Methane is a greenhouse gas that is 28 times more potent (per unit mass) than CO2.[107] [108] [109]
  • When combusted, fossil fuels emit the following amounts of CO2:

Pounds of CO2 per million Btu

Natural gas

117

Propane

139

Gasoline

157

Diesel fuel & heating oil

161

Coal

206-229

[110]

* Biofuels such as ethanol generate CO2 when burned, but the crops used to make these fuels absorb an equal amount of CO2 as they grow. However, planting, fertilizing, harvesting, processing, and distributing ethanol emits more CO2 than extracting, refining, and distributing gasoline.[111] [112] [113] [114] [115]

* Per the U.S. Congressional Budget Office (CBO), lifecycle analyses comparing CO2 emissions of corn-based ethanol and gasoline have produced varying results, but the most authoritative study in the eyes of the federal government (conducted by Argonne National Laboratory) estimates that, on average, corn-based ethanol produces about 20% less CO2 than gasoline.[116]

* Another type of biofuel called cellulosic ethanol has the potential to produce 60-95% less CO2 emissions than gasoline. This fuel is more difficult to manufacture than regular ethanol, and as of 2016, producers have been unable to make enough of it to meet the mandated amounts specified in federal law.[117] [118] [119] [120] [121] [122] [123]

* Converting undeveloped land to cultivate crops for biofuels creates CO2 emissions because existing plant life is removed and the soil is disrupted. If this land is repeatedly used to produce biofuels, the net CO2 emissions will be less than using fossil fuels. The timeframe until this breakeven point occurs depends upon factors such as the type of land converted and type of biofuel produced. Per a 2008 paper in the journal Science, the CO2 breakeven time of converting:

  • wetter portions of Brazil’s woodland/savanna region to produce sugarcane ethanol is about 17 years.
  • dryer portions of Brazil’s woodland/savanna region to produce soy biodiesel is about 37 years.
  • central grasslands of the U.S. to produce corn ethanol is about 93 years.
  • lowland tropical rainforest of Indonesia and Malaysia to produce palm biodiesel is about 320 years.
  • Amazonian rainforest to produce soy biodiesel is about 320 years.
  • tropical peatland rainforest to produce palm biodiesel is about 840 years.[124]

* Per the U.S. Energy Information Administration:

Most of the biodiesel produced in the United States is made from soybean oil. Some biodiesel is also produced from used oils or fats, including recycled restaurant grease. In some parts of the world, large areas of natural vegetation and forests have been cleared and burned to grow soybeans and palm oil trees to make biodiesel. The negative environmental impacts of land clearing may be greater than any potential benefits of using biodiesel produced from soybeans and palm oil trees.[125]

* Facts about greenhouse gases and climate change are detailed in Just Facts’ research on global warming.


Efficiency

* In order to perform useful work, energy usually must be converted from one form to another. Most energy on earth ultimately comes from the sun, and this energy typically undergoes multiple conversions before it is used to accomplish a particular task. For example, the energy that ultimately powers a light bulb may have the following history:

  • The process of fusion converts the nuclear energy of elements in the sun into sunlight (electromagnetic energy).
  • When sunlight strikes the earth’s oceans, some of it is converted to thermal energy.
  • This thermal energy heats the water and causes it to evaporate and rise, thus converting some of it to gravitational energy.
  • When this water falls as rain, it fills rivers that drive the turbines of hydroelectric dams, thus converting some of it to mechanical energy.
  • This mechanical energy is used to turn generators, thus converting some of it to electrical energy.
  • When this electrical energy flows through light bulbs, some of it is converted back to electromagnetic energy (light).[126] [127]

* With each conversion process, some amount of the energy is dispersed, thus making it less useful for performing work. Per the U.S. National Academy of Sciences:

Every time energy changes forms, some portion is “lost.” It doesn’t disappear, of course. In nature, energy is always conserved. That is, there is exactly as much of it around after something happens as there was before. But with each change, some amount of the original energy turns into forms we don’t want or can’t use, typically as so-called waste heat that is so diffuse it can’t be captured.
 
Reducing the amount lost – also known as increasing efficiency – is as important to our energy future as finding new sources because gigantic amounts of energy are lost every minute of every day in conversions.[128] [129] [130] [131]

* In the U.S. from 1949 to 2015, energy consumption per inflation-adjusted dollar of economic output decreased by 63%:

Energy Consumption per Economic Output

[132]

* Homes built in the U.S. from 2000-2009 are about 30% larger than homes built prior to this period, but they use about 2% more total energy. This result is primarily due to better insulation and increased efficiencies of heating and air conditioning technologies.[133]

* Homes built in the U.S. from 2000-2009 use about 18% more energy on appliances, electronics, and lighting than older homes.[134] This is because newer homes are more likely to have “dishwashers, clothes washers, clothes dryers, and two or more refrigerators.” Also, because they have more square footage, newer homes tend to have more “computers, TVs, and TV peripherals such as digital video recorders (DVRs) and video game systems.”[135]

* Increasing the efficiency of electronics, appliances, and lighting reduce the demand for energy and can save consumers money if the added cost of making these products more efficient does not exceed the cost of the energy saved.[136] [137]


* Energy Star is a joint program of the U.S. Environmental Protection Agency and Department of Energy. Per the program’s website:

If looking for new household products, look for ones that have earned the Energy Star. They meet strict energy efficiency guidelines set by the EPA and US Department of Energy.[138]

* In 2010, the U.S. Government Accountability Office (GAO) published an investigation of Energy Star in which GAO submitted 20 “bogus products” for approval. Fifteen of the products were approved, 2 were rejected, and 3 were unanswered at the time the report was published. Among the products certified as Energy Star compliant were:

  • a gasoline powered alarm clock.
  • a geothermal heat pump eligible for federal tax credits and state rebate programs that purportedly had higher efficiency than any Energy Star product.
  • a computer monitor that was approved within 30 minutes of submission.
  • “a room cleaner represented by a photograph of a feather duster adhered to a space heater on our [fake] manufacturer’s Web site.”
Energy Star Approved Room Cleaner

[139]


* The U.S. Green Building Council, per its website, is a “nonprofit organization committed to a prosperous and sustainable future for our nation through cost-efficient and energy-saving green buildings.”[140] This organization provides various types of green building certifications that qualify the owners for government incentives, such as tax breaks and zoning allowances. This rating system is named LEED for “Leadership in Energy and Environmental Design.”[141]

* In 2012, USA Today conducted an investigation of schools with green building certifications (such as LEED) and found:

  • “More than 200 states, federal agencies and municipalities require LEED certification for public buildings.”
  • out of 239 schools in the Houston (Texas) Independent School District, three newly built “green schools” ranked 46th, 155th, and 239th for energy costs per student.
  • “Building a LEED-certified school often adds 2% to 3% to construction costs, and as much as 10% in the case of a Selinsgrove, Pa., high school….”
  • a Green Building Council brochure had claimed that “green schools save money” based upon pre-construction cost estimates of 30 schools. One of these schools, located in Olympia, Washington, was projected to use 28% less energy than conventional schools. In its’ first two years of operations, the school used 19% more energy than conventional schools.
  • a Green Building Council brochure had claimed that “green schools help improve student performance,” but a USA Today “review of student test scores for 65 schools in 11 states that have been rebuilt to get LEED certification and have been open for at least two years” found “no clear pattern” of improved student performance.[142]
     

* Per the U.S. National Academy of Sciences:

Another familiar form of conversion loss occurs in a vehicle’s internal combustion engine. The chemical energy in the gasoline is converted to heat energy, which provides pressure on the pistons. That mechanical energy is then transferred to the wheels, increasing the vehicle’s kinetic energy. Even with a host of modern improvements, current vehicles use only about 20% of the energy content of the fuel as power, with the rest wasted as heat.
 
Electric motors typically have much higher efficiency ratings. But the rating only describes how much of the electricity input they turn into power; it does not reflect how much of the original, primary energy is lost in generating the electricity in the first place and then getting it to the motor.
 
Efficiencies of heat engines can be improved further, but only to a degree. Principles of physics place upper limits on how efficient they can be. Still, efforts are being made to capture more of the energy that is lost and to make use of it. This already happens in vehicles in the winter months, when heat loss is captured and used to warm the interior for passengers.[143] [144]

Costs of Transportation Fuels

* Transportation fuels have different energy densities, and thus, the price per volume of each fuel does not accurately reflect the energy supplied to consumers. For example, the energy content of a gallon of ethanol is 31% less than a gallon of gasoline. Hence, a car fueled with E85 (a mixture of 70-85% ethanol and 15-30% gasoline) will get 25-30% less miles per gallon than the same car when it is fueled with pure gasoline.[145] [146] [147] [148] [149]

* Like ethanol, the volume of biodiesel blended with regular diesel is shown by a number that follows the first letter of the named fuel. Thus, B20 contains 20% biodiesel and 80% regular diesel.[150]

* On an energy-equivalent basis, the average subsidized retail prices (including taxes) for transportation fuels during 2015 were as follows:

Fuel

Nationwide Average Price in

Gasoline-Gallon Equivalents

Price Relative

to Gasoline

Compressed Natural Gas

$2.10

-17%

Diesel

$2.56

0%

Biodiesel (B20)

$2.64

4%

Gasoline

$2.55

0%

Propane

$4.12

62%

Biodiesel (B100)

$3.62

42%

Ethanol (E85)

$3.04

20%

[151]

* A federal law known as the “Renewable Fuel Standard” requires U.S. consumers to use certain amounts of ethanol and other biofuels. This mandate uses a compliance mechanism that transfers some of the costs of producing these fuels from biofuel companies to petroleum companies. These added costs are then passed on to consumers in the form of higher gas prices.[152] [153] [154] [155]

* During 2015, a federal tax credit subsidized biodiesel at a rate of $1.00 per gallon.[156]

* Federal payments, tax breaks, loans, and loan guarantees subsidize petroleum and natural gas production at a rate of about $0.01 per gasoline-gallon equivalent.[157]

* Combining the data above yields the following average prices for transportation fuels during 2015 without federal subsidies:

Fuel

Unsubsidized Price in

Gasoline-Gallon Equivalents

Unsubsidized Price

Relative to Gasoline

Compressed Natural Gas

$2.11

-17%

Diesel

$2.56

0%

Biodiesel (B20)

$2.81

10%

Gasoline

$2.55

0%

Propane

$4.12

62%

Biodiesel (B100)

$5.56

118%

Ethanol (E85)

$3.51

38%

[158]


Costs of Electricity

* From 1929 to 1967, the inflation-adjusted average price of electricity for U.S. residential customers declined from about 60 cents per kilowatt hour to 10 cents, and it stayed roughly around this figure through 2012.[159]

* The inflation-adjusted average prices of electricity since 2004 for all U.S. consumers and the four major energy sectors are shown in the graph below:

Inflation-Adjusted Average Prices of Electricity in the U.S.

[160]

* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:

  • the time of the day, which influences the usage of lighting, computers, and other electric devices.
  • the weather, which influences the usage of heating, air conditioning, and ventilation systems.[161] [162] [163]

* As shown in the following graph, the terms “baseload” and “peak load” are used to describe the minimum and maximum demands for electricity over a given time period. The term “intermediate load” is used to describe the range between them.[164] [165]

Electricity Load Curve Example

[166]

* Coal is the dominant energy source for generating baseload capacity, because low fuel costs make coal plants inexpensive to run continuously, which is ideal for generating baseload capacity. For the same reason, nuclear power is a primary source of baseload capacity. Natural gas, hydropower, geothermal, and waste-to-energy plants are also sources of baseload capacity.[167] [168] [169] [170]

* Natural gas is the dominant energy source for generating intermediate and peak load capacity because natural gas power plants can ramp up and down quickly, which is ideal for intermediate and peak load capacity.[171] [172] [173] [174]

* In 2009, natural gas became competitive with coal for generating baseload capacity in some areas of the U.S. This was primarily due to increased domestic natural gas production, which reduced prices. Other factors included increased coal prices, stricter environmental regulations, and expansion of natural gas pipelines.[175] [176] [177] [178]

* In 2012, both coal and natural gas fuels were competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[179]

* For existing power plants, natural gas plants that employ a high efficiency technology called “combined cycle” can generate baseload power less expensively than coal plants when natural gas is about 1.5 times the price of coal.[180] [181] [182] In 2015, the average energy-equivalent price paid by electric power plants for natural gas was about 1.5 times the price of coal.[183]

Inflation-Adjusted Fossil Fuel Costs of Electric Power Plants

[184] [185]

* Per the U.S. Energy Information Administration (EIA), electric utilities and government entities that regulate them:

forecast the demand for electricity at the time of the peak, and then identify existing and potential generating resources needed to satisfy that demand, plus enough additional resources to provide a comfortable reserve margin. The goal is to minimize the costs associated with new capacity investments while ensuring reliability for customers.[186] [187] [188]

* Determining which electricity-generating technologies will provide the lowest cost while maintaining reliability is complicated by the following factors:

  • Power plants are capital-intensive and have lifespans measured in decades. Because these are long-term investments, there is ample time for market conditions and government energy polices to change, and this creates risk.[189] [190] [191] [192] [193] [194]
  • Utilities must produce enough electricity to meet their customers’ demands on a second-by-second basis, and the costs of generating this electricity vary depending upon when it is produced. During periods of high demand, electricity is more expensive to generate. Thus, technologies that generate electricity on demand have more value to utilities than intermittent resources, such as wind and solar.[195] [196] [197] [198] [199] [200] [201]
  • Decisions to invest in new generating capacity frequently involve factors that are unique to each utility and each point in time.[202]

* A commonly cited measure of the costs of building and operating new power plants is the “levelized cost” data published by EIA. Levelized costs reflect “both the capital and operating costs of deploying and running new utility-scale generation capacity of any given type.”[203] [204] Per EIA:

The direct comparison of LCOE [levelized cost of electricity] across technologies to determine the economic competitiveness of various generation alternatives is problematic and potentially misleading.”[205] [206]

* The following features, caveats, and limitations are inherent in EIA’s levelized costs:

  • They remove the effects of government subsidies.[207]
  • They account for the costs of buying or leasing land to operate the generation facilities.[208]
  • They do not remove the effects of taxes or government regulations.[209] [210]
  • They do not measure actual costs but are projections of future costs.[211]
  • They vary with EIA’s assumptions:
    • In 2011, EIA reduced the projected 2016 levelized cost for wind by 35% below its projection from one year earlier.
    • In the same projections, EIA reduced the cost for photovoltaic (PV) solar by 47%.[212]
    • In 2015, EIA reduced the projected 2020 levelized capital cost for geothermal by 57% below its estimate from two years earlier.[213] [214]
  • They do not provide a comprehensive projection of future costs, because they estimate the cost of building and operating one new power plant of each technology. Beyond that, the prices of geothermal, wind, and hydropower are subject to change.[215]
  • EIA does not have a monitoring and feedback mechanism to test the accuracy of previous projections.[216]
  • The projections do not account for the fact that intermittent electricity is less valuable than electricity that can be dispatched on demand. Per EIA, the levelized costs for wind and solar “are not directly comparable to those for other technologies” and are therefore “listed separately in the tables, because caution should be used when comparing them to one another.”[217] [218] [219]
  • They do not account for the physical lifespan of different capital investments. Instead, they assume that all types of generation capacity have the same financial life (30 years).[220] [221] Differing technologies have different physical lifespans:
    • The majority of nuclear power plants have been licensed to operate for 60 years.[222]
    • Per a 2008 Congressional Budget Office report, “numerous power stations built in the first half of the previous century are still in use.”[223] [224]
    • Per a 2013 report commissioned by EIA, solar panels have an expected life of 20-30 years.[225]
  • They add a 3-percentage premium to the financing costs of coal power plants to account for risks that government may tax or regulate greenhouse gases.[226] In 2013, this increased EIA’s projected 2018 levelized cost for coal by 19%.[227]
  • They do not compare the costs of replacing existing capacity with new capacity. Unless the costs of building and operating new capacity are lower than the costs of operating existing capacity, there is an economic disincentive to displace existing plants.[228] [229]
  • They only analyze utility-scale systems.[230] Rooftop solar systems, which are typically installed on homes and commercial buildings, are more expensive than utility-scale systems. This is because utility-scale systems benefit from economies of scale.[231] [232]

* In 2015, EIA projected the following levelized costs for plants that begin generating electricity in 2020:

Plant type (lowest cost option from each major category)

Cost (2013$/megawatthour)

Cost Increase Relative to Natural Gas

Dispatchable Technologies

Natural Gas Advanced Combined Cycle

72.6

0%

Geothermal

47.8

-34%

Conventional Coal

95.1

31%

Advanced Nuclear

95.2

31%

Non-Dispatchable Technologies

Onshore Wind

73.6

1%

Hydropower

83.5

15%

PV Solar

125.3

73%

[233]

* Per EIA, “a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost.” Calculating these costs involves a greater degree of complication than levelized costs.[234] [235]

* In July 2013, EIA published a preliminary discussion paper using avoided costs and levelized costs to compare the projected 2018 and 2035 values of advanced combined cycle natural gas (Adv CC), onshore wind, and PV solar with different subsidies given to wind and solar.[236] Because there is significant variability in factors that affect electricity costs and values in different regions of the country, the paper contained assessments of 22 regions within the U.S. electricity system. It found that without subsidies for wind and with a 10% investment tax credit for solar:

  • In 2018, the projected economic value of the wind and solar systems is “negative and significantly below” natural gas advanced combined cycle projects “in all regions.”
  • By 2035, the economic value of onshore wind is positive in 6 of 20 regions where the technology can be built, and in 3 of 21 regions for solar PV (with 5 additional regions close to breakeven).”
  • “Direct comparison of LCOE values significantly understate the advantage of Adv CC relative to onshore wind in terms of economic value in all regions, while overstating the advantage of Adv CC relative to solar PV….”
  • “Solar LCOE remains substantially higher than wind LCOE throughout the projection period….”[237]

* The following features, caveats, and limitations are inherent in this analysis:

  • It is based on projections of changing future economic conditions, such as rising natural gas prices starting around 2025.[238] [239]
  • It does not provide an analysis of solar without the effect of government subsidies.[240]
  • It does not remove the effects of existing taxes or government regulations.[241] [242]
  • It does not provide a comprehensive projection of future costs, because it estimates the cost of building and operating one new power plant of each technology. Beyond that, the prices of geothermal, wind, and hydropower are subject to change.[243]
  • It does not account for the physical lifespan of different capital investments. Instead, it assumes that all types of generation capacity have the same financial life (30 years).[244]
  • It only analyzes utility-scale systems.[245] Rooftop solar systems, which are typically installed on homes and commercial buildings, are more expensive than utility-scale systems. This is because utility-scale systems are larger and benefit from economies of scale.[246] [247]

* In 2015, EIA used levelized costs and avoided costs to estimate which type of plants would be economically competitive to build and begin producing electricity in 2020. Positive values indicate an economic incentive to build, and negative values indicate a disincentive:[248]

Plant type (lowest cost option from each major category)

Incentive (Levelized Minus Avoided Costs)

Incentive Relative to Natural Gas

Dispatchable Technologies

Natural Gas Advanced Combined Cycle

-1

0

Geothermal

27

28

Conventional Coal

-24

-23

Advanced Nuclear

-23

-22

Non-Dispatchable Technologies

Onshore Wind

-9

-8

Hydropower

-14

-13

PV Solar

-34

-33

[249]

* Forest product companies often use byproducts from their operations to generate their own electricity.[250] During 2015, wood generated 1.0% of all electricity in the U.S., as compared to 0.9% for solar and 0.4% for geothermal.[251]

* Oil and biofuels are rarely used to create electricity, because they are significantly more costly than the major sources of electricity.[252] [253] In 2015, the average energy-equivalent price paid by electric power plants for petroleum was about 3.1 times the price of coal.[254]

Petroleum

* Petroleum is a class of fossil fuels that are generally liquid at atmospheric pressure, although broader definitions of the term also include some gases and solids. The terms “petroleum” and “crude oil” are sometimes used synonymously, although petroleum is typically defined to include several other types of fossil fuels.[255] [256]

* Petroleum is primarily comprised of organic compounds called hydrocarbons, which consist of carbon and hydrogen. Other common elements of petroleum are nitrogen, oxygen, and sulfur.[257] [258] [259]

* Petroleum is mainly thought to be formed of diverse marine organisms that were buried by sediments and transformed by heat, pressure, and time.[260] [261] [262]

* The first oil well was drilled in 1857, the first intercontinental oil shipment occurred in 1859, and the first modern oil refinery commenced operations in 1862. By the 1870s, “refineries, tank cars, and pipelines had become characteristic features of the industry,” and by 1874, U.S. crude oil production had grown to 10 million barrels per year.[263]

* Today, the vast majority of crude oil is transported via pipelines and ships, and most refined petroleum fuels are transported from refineries to wholesale terminals through pipelines. Pipelines are the safest and most economical means of transporting petroleum in the U.S.[264] [265] [266] [267] [268]

* Petroleum is used to manufacture wide-ranging products, such as gasoline, diesel fuel, jet fuel, heating oil, lubricants, asphalt, propane, synthetic fabrics, plastics, paints, fertilizers, and soaps.[269] [270]

* In 2015, petroleum supplied:

  • 35% of all primary energy consumed in the U.S.
  • 92% of primary energy consumed in the transportation sector.
  • 39% of primary energy consumed in the industrial sector (not including energy purchased from electric power utilities).
  • 15% of primary energy consumed in the residential and commercial sectors (not including energy purchased from electric power utilities).
  • 1% of primary energy consumed in the electric power sector.[271]

Consumption, Production, Imports, and Prices

* In 2015, the U.S. consumed about 6.7 billion gallons of petroleum, 25% of which was imported.[272]

* U.S. petroleum consumption and net imports have declined since the mid-2000s, primarily due to the economic recession, increases in domestic crude oil production, use of renewable fuels, and efficiency improvements:[273] [274]

Petroleum Consumption and Production

[275]

* In 2014, U.S. net petroleum imports were distributed as follows:

  • 61% came from countries in the Western Hemisphere and 37% from the Persian Gulf.[276]
  • Among the top five countries, 51% came from Canada, 23% from Saudi Arabia, 14% from Venezuela, 7% from Iraq, and 6% from Russia.[277]
  • 59% came from nations that are members of the Organization of the Petroleum Exporting Countries (OPEC),[278] an intergovernmental body formed to “coordinate and unify the petroleum policies of its member countries.”[279] OPEC members include: Algeria, Angola, Ecuador, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela.[280]

* Since OPEC’s founding in 1960, its member nations have adopted various strategies to exert control over the petroleum market. One of their more common strategies has been to limit their petroleum production in order to boost prices and increase their profits.[281] [282] [283]

* OPEC nations have also adopted the opposite strategy of maximizing their petroleum production in order to drive down prices, force their competitors out of business, and grow their market share. Some OPEC nations have recently done this in response to increased production from non-OPEC countries.[284] [285] [286] [287] [288] [289]

US Imports from OPEC

[290]

* Crude oil prices are affected by global and local factors that impact the supply of petroleum and the demand for petroleum products, such as economic growth and recessions, OPEC policies, political unrest, and technological advancements.[291] [292] [293] [294]

Inflation-Adjusted Crude Oil Prices

[295]

* In the U.S. during 2015, the average landed (i.e., delivered) price of crude oil from selected OPEC nations was 8% more than the average price of domestic crude, and the average landed price of crude from selected non-OPEC nations was 1% less than the average price of domestic crude.[296]

* In 2015, the average retail price of a gallon of regular-grade gasoline in the U.S. was $2.42. Crude oil accounted for 48% of this price, refining costs and profits accounted for 19%, federal and state taxes accounted for 19%, and distribution and marketing accounted for 14%.[297]


Extraction Methods

* Crude oil resources[298] can be grouped into four major categories based upon their accessibility:

  1. conventional oil, which is located in porous rocks and reservoirs that allow the oil to freely flow to the surface of the earth when it is accessed through drilling.[299] [300]
  1. tight oil (sometimes called shale oil[301] [302] [303]), which is located in semi-porous or non-porous rocks that don’t allow the oil to freely flow when accessed through drilling. This type of petroleum can be extracted by using a combination of technologies known as horizontal drilling and hydraulic fracturing (described below).[304] [305] [306]
  1. oil sands (sometimes called tar sands), which are comprised of clay, sand, water, and a thick oil known as bitumen. Bitumen it too thick to pump from the ground, and thus, oil sands are generally mined and then the bitumen is extracted.[307] [308]
  1. oil shale (note the difference in word order from shale oil), which is rock containing solid hydrocarbons that become liquid and can be extracted after being heated to 650-1,000 degrees Fahrenheit. At the moment, it is not profitable to extract petroleum from oil shale.[309] [310] [311] [312]

* Horizontal drilling involves penetrating the ground vertically (like traditional drilling) and then turning horizontally in order to drill along the layer that contains the fossil fuel resources. This method of drilling exposes more of the fossil fuel resources to the bore of each well, thus increasing yields, decreasing the surface footprint of drilling operations, and decreasing unwanted output from the wells, such as water.[313] [314]

Horizontal Drilling

[315]

* Horizontal drilling was first successfully employed in 1929 and has been used commercially since the late 1980s. By 1990, more than 1,000 horizontal wells were drilled worldwide, roughly 85% of which were in Texas.[316]

* Hydraulic fracturing or fracking involves injecting fluids at high pressures from the bore of the well into the layer that contains the fossil fuel resources. This process creates fractures in the rock, which allows oil to flow to the bore of the well. The fluids used for fracking typically contain sand or ceramic beads that serve to hold open the fractures after they have been created. This fluid also contains varying chemicals that are used for purposes such as reducing friction and preventing pipe corrosion.[317] [318] [319] (A detailed description of the process is shown in the video below.)

* Hydraulic fracturing was first successfully employed in 1947 and has been used commercially since the 1950s. By 1955, more than 100,000 fracking treatments were performed.[320]

* Since the mid-2000s, technological advancements and market conditions have made it economically worthwhile to extract tight oil by using a combination of horizontal drilling and hydraulic fracturing.[321] [322] [323] [324] [325] [326] The process is shown in this video:

* From 2005 to 2015, U.S. crude oil production increased by 65%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in tight oil formations.[327] [328] [329] [330] [331] [332]

* As of 2015, horizontal drilling coupled with hydraulic fracturing had not been widely used to extract tight oil outside the U.S.[333] [334] [335] [336] [337] In 2013, the U.S. Energy Information Administration (EIA) estimated that 10% of worldwide technically recoverable oil resources are located in tight formations.[338]

* For facts about the environmental impacts of horizontal drilling and hydraulic fracturing, visit the politics section of this research.


Natural Resources

* Estimates of crude oil resources are uncertain and subject to change, particularly for tight oil formations.[339] [340]

* Definitions used for estimates of fossil fuel resources include:

  • proved reserves, which are known resources that can be profitably extracted at current prices with current technologies.[341] [342]
  • technically recoverable reserves, which are resources that can be extracted with current technology regardless of economic viability.[343] [344] [345]
  • undiscovered recoverable reserves, which are resources that are not yet discovered but are “estimated to exist in favorable geologic settings.[346]

* Per EIA, it is “misleading” to make assessments about total fossil fuel resources on the basis of proved reserves. This is because:

Proved reserves are an accounting concept that is based on known projects, and it is not an appropriate measure for judging total resource availability in the long term. Over time, global reserves will likely increase as new technologies increase production at existing fields and as new projects are developed.[347] [348] [349] [350]

* In 1955, America’s proved reserves of oil were equal to 11-12 years of U.S. oil consumption at that time.[351]

* In 1977, the U.S. had 31.8 billion barrels of proved crude oil reserves. If this represented all U.S. crude oil resources, the U.S. would have run out of oil in 1988.[352]

* As of 2013, the U.S. Energy Information Administration (EIA) estimates that the U.S. has 260 billion barrels of technically recoverable crude oil. This figure does not include:

  • oil shale.
  • resources located in areas “areas where drilling is officially prohibited.”
  • about 7 billion barrels of offshore oil located in areas that are not expected to be drilled by 2040.[353]

* 260 billion barrels of technically recoverable crude oil is roughly equivalent to:

  • 76 years of U.S. crude oil production at the 2015 production rate.[354]
  • 50 years of U.S. crude oil consumption at the 2015 consumption rate.[355]

* As of 2013, the U.S. Energy Information Administration (EIA) estimates that the world has 3,357 billion barrels of technically recoverable crude oil. This figure does not include several crude oil resources, such as offshore shale oil, shale oil formations in the Middle East and Caspian region, tight sandstone formations, and other formations that have not yet been quantified by EIA.[356]

* 3,357 billion barrels of technically recoverable crude oil is equivalent to 108 years of worldwide petroleum production at the 2010 production rate.[357]

* According to a 2009 estimate by the U.S. Department of Energy, worldwide oil shale reserves, which are not included in the above estimates of technically recoverable crude oil, are equivalent to about 3.7 trillion barrels of crude oil. In 2009, this was roughly 40% more than all other global reserves of petroleum. About two thirds of these oil shale reserves are located in the U.S.[358]

* In 2010, the U.S. Department of the Interior reported that roughly 45% to 80% of oil shale reserves may be technically recoverable.[359]

* The largest known oil shale reserves are located in the Green River Formation, which is situated in southwestern Wyoming, northeastern Utah, and northwestern Colorado.[360] [361]

* In 2013, the U.S. Department of the Interior reported that the Green River Formation contains about 4.3 trillion barrels of oil shale, and roughly 8% to 27% of this has “a high potential for development.”[362] This amounts to:

  • 68 to 222 years of U.S. crude oil consumption at the 2015 consumption rate.[363]
  • 103 to 334 years of U.S. crude oil production at the 2015 production rate.[364]
  • 11 to 37 years of worldwide petroleum production at the 2010 production rate.[365]

* Per the U.S. Department of the Interior:

More than 70% of the total oil shale acreage in the Green River Formation, including the richest and thickest oil shale deposits, is under federally owned and managed lands. Thus, the federal government directly controls access to the most commercially attractive portions of the oil shale resource base.[366]

* Compiling the above estimates of technically recoverable crude oil and Green River oil shale with high potential for development:

  • the U.S. has 0.6 to 1.4 trillion barrels of crude oil and oil shale reserves, which is equivalent to 112 to 265 years of U.S. crude oil consumption at the 2015 consumption rate.[367]
  • the world has 3.7 to 4.5 trillion barrels of crude oil and oil shale reserves, which is equivalent to 119 to 145 years of worldwide petroleum production at the 2010 production rate.[368]

Natural Gas

* Natural gas is a mixture of fossil fuels (mostly methane) that are gaseous at atmospheric pressure and room temperature. Natural gas is sometimes defined differently because certain fossil fuels that are gases inside the earth become liquids when brought to the surface, and because certain natural gases (like propane) are commonly processed into liquids called natural gas liquids.[369] [370] [371]

* The U.S. Energy Information Administration (EIA) typically classifies natural gas liquids as petroleum. Therefore, the above data on petroleum production, consumption, etc. generally includes these natural gas liquids, and the corresponding data below on natural gas generally does not.[372]

* Natural gas is primarily comprised of organic compounds called hydrocarbons, which consist of carbon and hydrogen.[373]

* Natural gas is mainly thought to be formed of diverse marine organisms that were buried by sediments and transformed by heat, pressure, and time.[374] [375] [376]

* Natural gas and crude oil are often found in the same geological formations. In 2014, roughly 18% of all natural gas extracted from the ground in the U.S. came from crude oil wells.[377] [378]

* The first known natural gas well was drilled in China in 211 BC, and the gas was used for drying salt. The first North American natural gas well was drilled in Fredonia, N.Y., in 1821, and the gas was used for lighting and cooking.[379]

* The vast majority of natural gas is currently transported through pipelines. Prior to the early-to-mid 1900s, natural gas was not widely used because it was difficult to transport large amounts of it over long distances. Since then, advances in pipeline technology and infrastructure have made it economical to transport large volumes of natural gas in many circumstances.[380] [381] [382]

* In circumstances where pipelines are not practical or cost-effective (like when shipping overseas), it is more expensive to ship natural gas than crude oil, because the density of natural gas is 942 times less than crude oil. When shipping overseas, natural gas is often liquefied by cooling it to -258ºF (-161ºC), which reduces its volume by a factor of 610. During this process, about 8-10% of the gas is consumed to generate the energy to cool the gas to these subzero temperatures.[383] [384] [385] [386]

* Before the widespread construction of pipelines, natural gas produced from oil wells was often discarded through burning it (called flaring) or releasing it into the air (called venting).[387] [388]

* In 1949, 11.3% of natural gas extracted from the ground in the U.S. was vented or flared. By 1971, this figure declined to 1.2%, and since then, it has averaged 0.7%.[389]

* In 2014, 1.0% of U.S. natural gas production was vented or flared.[390] Worldwide in 2010, roughly 4.4% of natural gas production was flared (data on venting is unavailable).[391]

* Natural gas and natural gas liquids are combusted for purposes such as space heating, cooking, and electricity generation. Natural gas liquids are also used as ingredients in wide-ranging products, such as plastics, fertilizers, and detergents.[392] [393] [394] [395] [396]

* In 2015, natural gas supplied:

  • 28% of all primary energy consumed in the U.S.
  • 3% of primary energy consumed in the transportation sector.
  • 39% of primary energy consumed in the industrial sector (not including energy purchased from electric power utilities).
  • 76% of primary energy consumed in the residential and commercial sectors (not including energy purchased from electric power utilities).
  • 26% of primary energy consumed in the electric power sector.[397]

Consumption, Production, Imports, and Prices

* In 2015, the U.S. consumed about 27.5 trillion cubic feet of natural gas, 3% of which was imported:

Natural Gas Consumption, Production, Imports

[398]

* Between 2007 and 2015, the portion of U.S. natural gas consumption that was imported declined by 79%, primarily as a result of increased domestic production through technologies known as horizontal drilling and hydraulic fracturing (described below):

Natural Gas Imports

[399] [400] [401] [402]

* Natural gas prices are affected by factors that impact supply and demand, such as economic growth and recessions, weather, and technological advancements.[403] [404] [405] [406] Because natural gas is more difficult to transport than petroleum, natural gas prices are more affected by local and regional factors than petroleum prices, which are primarily driven by global factors.[407] [408] [409] [410] [411]

* In 2015, the average production price for natural gas was roughly $2.99 per thousand cubic feet, and the average price for residential consumers was $10.38 per thousand cubic feet.[412]

Inflation-Adjusted Average U.S. Natural Gas Prices

[413] [414]


Electricity

* In 2015, natural gas supplied 26% of the primary energy consumed in the U.S. electric power sector.[415] Because certain natural gas power plants are more efficient than coal power plants,[416] [417] and because some electricity is generated outside of the electric power sector, during 2015 natural gas supplied:

  • 32% of the electricity produced in the electric power sector.[418]
  • 33% of the electricity produced in all sectors.[419]

* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:

  • the time of the day, which influences the usage of lighting, computers, and other electric devices.
  • the weather, which influences the usage of heating, air conditioning, and ventilation systems.[420] [421] [422]

* As shown in the following graph, the terms “baseload” and “peak load” are used to describe the minimum and maximum demands for electricity over a given time period. The term “intermediate load” is used to describe the range between them.[423] [424]

Electricity Load Curve Example

[425]

* Natural gas is the dominant energy source for generating intermediate and peak load capacity because:

  • natural gas power plants can ramp up and down quickly, which is ideal for intermediate and peak load capacity.
  • natural gas power plants are less expensive to build than coal and nuclear power plants.[426] [427] [428] [429]

* Coal is the dominant energy source for generating baseload capacity because once built, low fuel costs make coal plants inexpensive to run continuously, which is ideal for generating baseload capacity.[430] [431] [432]

* In 2009, natural gas became competitive with coal for generating baseload capacity in some areas of the U.S. This was primarily due to increased domestic natural gas production, which reduced prices. Other factors included increased coal prices, stricter environmental regulations, and expansion of natural gas pipelines.[433] [434] [435] [436]

* In 2012, both coal and natural gas fuels were competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[437]

* Due to their higher efficiency, natural gas power plants that employ a technology called “combined cycle” can generate baseload power less expensively than coal plants when natural gas is about 1.5 times the price of coal.[438] [439] [440] In 2015, the average energy-equivalent price paid by electric power plants for natural gas was about 1.5 times the price of coal.[441]


Transportation

* In 2015, natural gas supplied 3% of the energy used in the U.S. transportation sector.[442]

* Between 2007 and 2013, the combination of increased oil prices, decreased natural gas prices, increased domestic natural gas production, and stricter environmental regulations created incentives to use natural gas more widely for transportation.[443] [444] [445] [446] Steep declines in oil prices since 2014 have made natural gas less competitive as a transportation fuel.[447] [448] [449]

* Other disincentives to the wider use of natural gas in transportation include (1) the capital costs of equipping service stations to dispense natural gas, and (2) the lower energy density (per unit volume) of compressed or liquefied natural gas, as compared to gasoline and diesel.[450] [451] [452] [453] [454] Per EIA:

Energy density and the cost, weight, and size of onboard energy storage are important characteristics of fuels for transportation. Fuels that require large, heavy, or expensive storage can reduce the space available to convey people and freight, weigh down a vehicle (making it operate less efficiently), or make it too costly to operate, even after taking account of cheaper fuels. Compared to gasoline and diesel, other options may have more energy per unit weight, but none have more energy per unit volume. …
 
… [C]ompressed fuels require heavy storage tanks, while cooled fuels require equipment to maintain low temperatures.[455]

* In 2012, the only factory-built compressed natural gas car available to non-fleet customers in the U.S. was the Honda Civic Natural Gas. It was the “cleanest internal-combustion vehicle ever tested by the U.S. Environmental Protection Agency.”[456] Compared to a similarly equipped Honda Civic EX, the natural gas model:

  • had 41-48% less range (220-248 miles versus 422).
  • had 29% less horsepower (110 hp versus 140).
  • had 14% less torque (110 lb-ft versus 128).
  • had 51% less trunk space (6.1 cubic feet versus 12.5).
  • cost 27% or $5,650 more ($26,925 versus $21,275).[457] [458] [459] [460]

* Based on the average nationwide prices of gasoline and compressed natural gas in July 2013, the 2012 Civic Natural Gas would recoup the $5,650 cost premium over the standard model after 111,000 miles of driving.[461]

* Based on the average nationwide prices of gasoline and compressed natural gas in 2015, the 2015 Civic Natural Gas would recoup the $5,700 cost premium over the standard model after more than two million miles of driving.[462]

* In 2015, Honda announced it was cancelling the Civic Natural Gas after 2015 due to low gasoline prices and a lack of consumer demand.[463]

* Per Vivek Chandra, a natural gas industry consultant and the author of Fundamentals of Natural Gas:[464]

Natural gas holds the greatest promise as a fuel for fleet vehicles that refuel at a central location, such as transit buses, short-haul delivery vehicles, taxis, government cars, and light trucks. There are currently approximately 65,000 natural gas vehicles (NGVs) in operation in the United States using CNG [compressed natural gas] and LNG [liquefied natural gas] as their main fuels.[465]

* Home fueling is possible with natural gas vehicles, but as of 2016, Honda does not recommend this for the Civic Natural Gas because “of moisture and other contaminants inherent in some natural gas supplies, and the inability of some home refueling systems to adequately dry the gas and remove contaminants….”[466]


Extraction Methods

* Natural gas resources can be grouped into two major categories based upon their accessibility:

  1. conventional natural gas, which is located in porous rocks and reservoirs that allow the gas to freely flow to the surface of the earth when it is accessed through drilling.[467] [468]
  1. shale gas or tight gas, which is located in semi-porous or non-porous rocks that don’t allow the gas to freely flow when accessed through drilling. This natural gas can be extracted by using a combination of technologies known as horizontal drilling and hydraulic fracturing.[469] [470] [471] [472]

* Horizontal drilling involves penetrating the ground vertically (like traditional drilling) and then turning horizontally in order to drill along the layer that contains the fossil fuel resources. This method of drilling exposes more of the fossil fuel resources to the bore of each well, thus increasing yields and decreasing the surface footprint of drilling operations.[473] [474]

Horizontal Drilling

[475]

* Horizontal drilling was first successfully employed in 1929 and has been used commercially since the late 1980s. By 1990, more than 1,000 horizontal wells were drilled worldwide, almost all for the purpose of extracting crude oil.[476]

* Hydraulic fracturing or fracking involves injecting fluids at high pressures from the bore of the well into the layer that contains the fossil fuel resources. This process creates fractures in the rock, which allows natural gas to flow to the bore of the well. The fluids used for fracking typically contain sand or ceramic beads that serve to hold open the fractures after they have been created. This fluid also contains varying chemicals that are used for purposes such as preventing pipe corrosion.[477] [478] (A detailed description of the process is shown in the video below.)

* Hydraulic fracturing was first successfully employed to drill for oil in 1947 and has been used commercially since the 1950s. By 1955, more than 100,000 fracking treatments were performed. In the 1980s and early 1990s, Texas oilman George Mitchell refined the process of fracking to extract natural gas from shale in a cost-effective manner.[479]

* In the early 2000s, horizontal drilling coupled with hydraulic fracturing became widely used to extract natural gas from shale. In the mid-2000s, the combination of these technologies also became widely used to extract oil from shale.[480] [481] [482] The process is shown in this video:

* From 2005 to 2015, U.S. natural gas production increased by 50%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in shale formations.[483] [484] [485]

* As of 2013, horizontal drilling coupled with hydraulic fracturing has not been widely used to extract natural gas outside the U.S.[486] [487] In 2013, the U.S. Energy Information Administration (EIA) estimated that 32% of worldwide technically recoverable natural gas resources are located in shale formations.[488]

* For facts about the environmental impacts of horizontal drilling and hydraulic fracturing, visit the politics section of this research.


Natural Resources

* Estimates of natural gas resources are uncertain and subject to change, particularly for shale formations.[489] [490]

* Definitions used for estimates of fossil fuel resources include:

  • proved reserves, which are known resources that can be profitably extracted at current prices with current technologies.[491] [492]
  • technically recoverable reserves, which are resources that can be extracted with current technology regardless of economic viability.[493] [494] [495]
  • undiscovered recoverable reserves, which are resources that are not yet discovered but are “estimated to exist in favorable geologic settings.[496]

* Per EIA, it is “misleading” to make assessments about total fossil fuel resources on the basis of proved reserves because “proved reserves are an accounting concept that is based on known projects, and it is not an appropriate measure for judging total resource availability in the long term.”[497] [498] [499] [500]

* In 1977, the U.S. had 207 trillion cubic feet of proved natural gas reserves. If this represented all U.S. natural gas resources, the U.S. would have run out of natural gas in 1989.[501]

* As of 2013, the U.S. Energy Information Administration (EIA) estimates that the U.S. has 2,276 trillion cubic feet of technically recoverable natural gas. This figure does not include resources located in areas “areas where drilling is officially prohibited,” and it does not include about 33 trillion cubic feet of offshore natural gas located in areas that are not expected to be drilled by 2040.[502]

* 2,276 trillion cubic feet of technically recoverable natural gas is equivalent to:

  • 84 years of U.S. natural gas production at the 2015 production rate.[503]
  • 83 years of U.S. natural gas consumption at the 2015 consumption rate.[504]

* 21,897 trillion cubic feet of technically recoverable natural gas is equivalent to 197 years of worldwide natural gas production at the 2010 production rate.[505]

* The figures above do not account for methane hydrates, which are “cage-like lattices of water molecules containing methane, the chief constituent of natural gas.” Globally, these resources are estimated to be equivalent to 10,000-100,000 trillion cubic feet of natural gas, or 90-900 years of worldwide natural gas production at the 2010 production rate.[506] [507]

* Per EIA, methane hydrates:

may represent one of the world’s largest reservoirs of carbon-based fuel. However, with abundant availability of natural gas from conventional and shale resources, there is no economic incentive to develop gas hydrate resources, and no commercial-scale technologies to exploit them have been demonstrated.[508]

Coal

* Coal is a class of combustible rocks that are at least 50% carbon by weight.[509] [510]

* Coal is categorized into different “ranks,” primarily depending upon how much of it is comprised of carbon. Coals with higher carbon content generally contain more energy and have a higher rank. The main ranks of coal (from lowest to highest) are lignite, subbituminous coal, bituminous coal, and anthracite.[511] [512] [513] [514]

* Coal is formed of plant materials that have been buried and transformed by pressure, heat, and time.[515]

* Coal may have been used as early as 3,000 years ago to smelt copper in China, and it was used in England for cooking during the era of the Roman Empire. The burning of coal to generate heat became widespread in Europe during the mid-1600s to early 1700s. Coal usage continued to expand and diversify through the 1800s, particularly as fuel for powering steam engines.[516] [517]

* Today, coal is the world’s leading fuel for generating electricity. Due to attributes such as low cost and widespread availability, coal accounted for 40% of global electricity production in 2012.[518] [519] [520]

* More than 90% of the coal produced in the U.S. is used to generate electricity.[521]

* Coal is also:

  • combusted to generate heat for industrial processes and for commercial, military, and institutional facilities.[522]
  • used as an ingredient for manufacturing products such as steels, plastics, waxes, pharmaceuticals, synthetic fibers, fertilizers, and pesticides.[523] [524] [525]

* Many nations have enacted polices to limit the use of coal in order to reduce greenhouse gases. Based upon these policies and other variables, the U.S. Energy Information Administration projected in 2016 that:

  • total electricity generation from coal will increase by 23% between 2012 and 2040.
  • coal will decrease from 40% of total world electricity generation in 2012 to 29% by 2040.
  • coal with continue “to be the largest single fuel used for electricity generation worldwide” through 2040.[526]

* In 2015, coal supplied:

  • 16% of all primary energy consumed in the U.S.
  • 37% of primary energy consumed in the electric power sector.
  • 7% of primary energy consumed in the industrial sector (not including energy purchased from electric power utilities).
  • 1% of primary energy consumed in the residential and commercial sectors (not including energy purchased from electric power utilities).[527]

* In 2014, the U.S. had 1,145 coal-fired electricity generating units located at 491 electric power plants.[528]

* Because coal power plants are less efficient than certain natural gas power plants,[529] [530] and because some electricity is generated outside of the electric power sector, during 2015 coal supplied:

  • 37% of the primary energy consumed in the U.S. electric power sector.[531]
  • 34% of the electricity produced in the U.S. electric power sector.[532]
  • 33% of the electricity produced in all U.S. energy sectors.[533]

Consumption, Production, Exports, and Prices

* In 2015, the U.S. produced 895 million short tons of coal, consumed 802 million short tons, and had net exports of 63 million short tons.[534] [535]

* Between 2008 and 2015, U.S. coal consumption declined by 28%, primarily as a result of lower natural gas prices and stricter environmental regulations:[536] [537] [538] [539]

Coal Production, Consumption, Exports

[540]

* In 2014, the average domestic price of coal was $35.72 per ton.[541]

Inflation-Adjusted Average U.S. Coal Prices

[542] [543]

* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:

  • the time of the day, which influences the usage of lighting, computers, and other electric devices.
  • the weather, which influences the usage of heating, air conditioning, and ventilation systems.[544] [545] [546]

* As shown in the following graph, the terms “baseload” and “peak load” are used to describe the minimum and maximum demands for electricity over a given time period. The term “intermediate load” is used to describe the range between them.[547] [548]

Electricity Load Curve Example

[549]

* Coal is the dominant energy source for generating baseload capacity because once built, low fuel costs make coal plants inexpensive to run continuously, which is ideal for generating baseload capacity.[550] [551] [552]

* Natural gas is the dominant energy source for generating intermediate and peak load capacity because:

  • natural gas power plants can ramp up and down quickly, which is ideal for intermediate and peak load capacity.
  • natural gas power plants are less expensive to build than coal and nuclear power plants.[553] [554] [555] [556]

* In 2009, natural gas became competitive with coal for generating baseload capacity in some areas of the U.S. This was primarily due to increased domestic natural gas production, which reduced prices. Other factors included increased coal prices, stricter environmental regulations, and expansion of natural gas pipelines.[557] [558] [559] [560]

* In 2012, both coal and natural gas fuels were competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[561]

* Due to their higher efficiency, natural gas power plants that employ a technology called “combined cycle” can generate baseload power less expensively than coal plants when natural gas is about 1.5 times the price of coal.[562] [563] [564] In 2015, the average energy-equivalent price paid by electric power plants for natural gas was about 1.5 times the price of coal.[565]


Mining

* In the U.S., coal is mined in two primary ways: surface mining and underground mining. Per the U.S. Department of Energy:

Surface mining accounts for about 60 percent of the coal produced in the United States. It is used mostly in the West where huge coal deposits lie near the surface and can be up to 100 feet thick.
 
In surface mining, bulldozers clear and level the mining area. Topsoil is removed and stored for later use in the land reclamation process. Specially designed machines … expose the coal bed. Smaller shovels load the coal into large trucks that remove the coal from the pit.
 
Before mining begins, coal companies must post bonds for each acre of land to be mined to assure that it will be properly reclaimed. In the reclamation process … the area restored as nearly as possible to its original contours. Since 1977, more than 2 million acres of coal mine lands have been reclaimed in this manner.
 
Where coal seams are too deep or the land is too hilly for surface mining, coal miners must go underground to extract the coal. Most underground mining takes place east of the Mississippi, especially in the Appalachian mountain states and is used to produce about 30 percent of U.S. coal today.[566]

* In 2014, 16 U.S. coal workers were killed while working.[567] [568] In conjunction with technological advances, improved safety measures, and stricter regulations,[569] [570] coal worker fatalities have declined from a high of 3,242 people in 1907 to a low of 16 people in 2014:

Coal Worker Fatalities

[571]

* Per the Encyclopædia Britannica:

Coal mines and coal-preparation plants caused much environmental damage in the past. Surface areas exposed during mining, as well as coal and rock waste (which were often dumped indiscriminately), weathered rapidly, producing abundant sediment and soluble chemical products such as sulfuric acid and iron sulfates. Nearby streams became clogged with sediment, iron oxides stained rocks, and “acid mine drainage” caused marked reductions in the numbers of plants and animals living in the vicinity. Potentially toxic elements, leached from the exposed coal and adjacent rocks, were released into the environment. Since the 1970s, however, stricter laws have significantly reduced the environmental damage caused by coal mining.[572]

Natural Resources

* The U.S. has more recoverable coal reserves than any other nation, amounting to one quarter of the world’s coal resources.[573] [574]

* Based on U.S. Energy Information Administration (EIA) estimates from 2011, the U.S. has roughly 262 billion short tons of recoverable coal reserves, comprised of 23 billion tons of lignite, 96 billion tons of subbituminous coal, 139 billion tons of bituminous coal, and 4 billion tons of anthracite. These resources amount to:

  • 285 years of lignite production at the 2011 production rate.
  • 187 years of subbituminous coal production at the 2011 production rate.
  • 277 years of bituminous coal production at the 2011 production rate.
  • 1,764 years of anthracite production at the 2011 production rate.[575] [576] [577]

Nuclear

* Nuclear energy is so-named because it is stored in the nuclei of atoms. Through the process of fission, this energy is transformed into heat, which can be used to power steam boilers that drive electricity-generating turbines.[578] [579]

* Uranium is the primary fuel used in nuclear power plants because the process of fission is most easily achieved with elements with heavy nuclei, and uranium is the “heaviest naturally-occurring element available in large quantities.”[580] [581]

* The world’s first controlled nuclear fission reactor was built in the U.S. by Italian physicist Enrico Fermi, and it became operational in 1942.[582] The world’s first nuclear-powered electricity plant was built in the Soviet Union, and it became operational in 1954.[583]

* Through fission, a single pound of uranium can generate as much energy as burning three million pounds of coal.[584]

* In 2015, nuclear energy supplied 8.5% of all primary energy consumed in the United States:

Nuclear Energy Usage

[585]

* In 2015, nuclear energy generated 19.5% of all electricity produced in the U.S.[586]


Baseload Power

* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:

  • the time of the day, which influences the usage of lighting, computers, and other electric devices.
  • the weather, which influences the usage of heating, air conditioning, and ventilation systems.[587] [588] [589]

* As shown in the following graph, the terms “baseload” and “peak load” are used to describe the minimum and maximum demands for electricity over a given time period. The term “intermediate load” is used to describe the range between them.[590] [591]

Electricity Load Curve Example

[592]

* Nuclear power is a major source of baseload capacity because once built, low fuel costs make nuclear plants inexpensive to run continuously, which is ideal for generating baseload capacity.[593] [594] [595]


Waste

* Because the products of nuclear fission emit hazardous levels of radiation, generate heat, and could be used in weapons called “dirty bombs,” they must be reprocessed and/or stored in secure locations and cooled.[596] [597] [598] [599] [600] [601]

* Waste and fuel from commercial nuclear power plants cannot accidentally or intentionally be used to produce a nuclear blast. Such explosions require different grades of materials than those used and produced by commercial power plants.[602] [603]

* Nuclear power plant operators must pay up-front fees to the federal government for the future costs of decommissioning of their plants, thus making it impossible for operators to avoid these costs through bankruptcy after the plant closes.[604] [605] [606]

* The Nuclear Waste Policy Act of 1982 required the federal government to:

  • take responsibility for storing waste from nuclear power plants and find at least one suitable location to store it.
  • collect fees from nuclear power plant operators for storing the waste.
  • start accepting waste from the power plants by 1998.[607] [608] [609] [610] [611]

* A 1987 law directed the federal government to evaluate storing the waste in the Yucca Mountain, which is located on a 230-square mile plot of federal land in the Mojave Desert of southern Nevada:[612] [613]

Yucca Mountain

[614]

* Current law limits the amount of fuel that could be stored at Yucca Mountain to 70,000 metric tons, which is about equal to the nation’s current nuclear waste. Per evaluations performed by the Department of Energy, at least 3-4 times this amount can be safely stored at Yucca.[615] [616]

* At a cost of hundreds of millions of dollars during the 1990s, the U.S. Department of Energy drilled a 5-mile long, 25-feet diameter tunnel into the Yucca Mountain, along with a 2-mile long tunnel that branches off of it.[617] [618] [619]

* A 2002 federal law approved the Yucca site for permanent nuclear waste storage.[620] [621]

* By 2006, Minnesota had banned the construction of new nuclear power plants, and 11 other states had restricted the construction of new plants until certain provisions for long-term disposal of nuclear waste are met.[622] [623] [624]

* In June 2008, the Bush administration Department of Energy (DOE) submitted an application to the Nuclear Regulatory Commission (NRC) for approval to construct a waste repository at Yucca Mountain.[625]

* In March 2009, the Obama administration DOE announced that it was going to terminate the Yucca Mountain repository. Inquiries to DOE by the U.S. Government Accountability Office and Nuclear Regulatory Commission found that the decision “was made for policy reasons, not technical or safety reasons.” Per the Obama administration DOE:

[The Energy] Secretary’s judgment is not that Yucca Mountain is unsafe or that there are flaws in the license application, but rather that it is not a workable option and that alternatives will better serve the public interest.[626] [627]

* After this announcement, the Obama administration moved to shut down the Yucca Mountain program by September 2010 by terminating leases and contracts, archiving documents, eliminating the jobs of all federal employees working on the project, and disposing or transferring federal assets used for the project. [628]

* Between 1983 and 2011, the federal government spent roughly $15 billion “to evaluate potential nuclear waste repository sites, evaluate the Yucca Mountain site in more depth, and develop and submit the license application for it.”[629]

* Between 1983 and 2011, nuclear power plant operators paid more than $30 billion in fees (including earned interest) to the federal government to dispose of nuclear waste. The government used $9.5 billion of these fees “to evaluate potential nuclear waste repository sites, evaluate the Yucca Mountain site in more depth, and develop and submit the license application for it.”[630] [631]

* At the end 2014, the U.S. had more than 74,000 metric tons of commercial nuclear waste, most of which is being stored at nuclear power plants.[632] [633] [634] [635]

* Due to a breach of federal government’s responsibility to start taking waste from power plants starting in 1998, the federal government has paid $5.3 billion in court-ordered damages and settlements to power plant operators as of September 2015.[636] [637]

* In 2015, the Inspector General of the Department of Energy estimated that the federal government’s total liabilities for breaching this responsibility will amount to $29 billion. The nuclear power industry estimates that it will be at least $50 billion.[638]

* In 2013, a three-judge panel of the District of Columbia Court of Appeals ruled (2-1) that the NRC “was violating federal law by declining to further process the license application” for the Yucca facility. The court ordered the NRC to continue this process.[639] [640]

* After this ruling, the NRC published reports in 2014 and 2016 finding that the Yucca facility could safely store nuclear waste for a million years.[641] [642] [643]


Safety

* A commonly utilized measure of radiation dosage is millisieverts (mSv). On average, each person receives 2.4 mSv per year of natural background radiation, typically varying from 1-13 mSv per year. Per the United Nations Scientific Committee on the Effects of Atomic Radiation, “sizeable population groups receive 10-20 mSv annually” of natural radiation. This does not include any radiation from human activities.[644] [645]

* Over the course of a lifetime, most people receive about 70-700 mSv of radiation from natural sources.[646]

* After tobacco smoke, the second leading cause of lung cancer in the U.S. is radon, a gas that arises from the decay of natural uranium, which is common in rocks and soils.[647] The EPA estimates that 14.4 percent of lung cancer deaths in the U.S. are related to radon.[648]

* Due to hot springs that leach a radioactive element from underground, 2,000 residents in the city of Ramsar, Iran, receive up to 260 mSv of natural background radiation per year. Per a 2002 paper in journal Health Physics, preliminary studies indicate an “apparent lack of ill effects among observed populations of these high dose rate areas….”[649]

* Regarding manmade sources of radiation, on average:

  • a person underdoing a CT scan receives a dose of 10 mSv.
  • a nuclear power plant worker receives a dose of 1 mSv per year.
  • the general population receives a dose of 0.0002 mSv per year as a result of the nuclear power industry.[650] [651]

* Concentrated (i.e., high-level, high-rate) radiation doses generally cause more harm than the same doses spread out over longer periods of time.[652] Concentrated radiation doses of:

  • more than 10,000 mSv are always fatal.
  • 1,000-10,000 mSv can cause radiation sickness (which may result in death) and can increase the risk of certain cancers.
  • 10-1,000 mSv have no immediate effects but may increase the long-term risk of certain cancers.[653]

* Two major studies of survivors of the 1945 atomic bombings in Hiroshima and Nagasaki have found increased rates of certain cancers among populations who received concentrated radiation doses below 100 mSv, but none of the results were statistically significant below this level.[654]

* The largest nuclear power accident in the world occurred in the city of Chernobyl in the Soviet Union in 1986.[655] A picture of the reactor after the accident is shown here:

Chernobyl Post-Accident

[656]

* Per the official summary of a 2006 three-volume report by the International Atomic Energy Agency, World Health Organization, U.N. Development Programme, Food and Agriculture Organization, U.N. Environment Programme, U.N. Office for the Coordination of Humanitarian Affairs, U.N. Scientific Committee on the Effects of Atomic Radiation, World Bank, and the governments of Belarus, the Russian Federation, and Ukraine:

  • “Approximately 1,000 on-site reactor staff and emergency workers were heavily exposed to high-level radiation on the first day of the accident….”
  • “More than 350,000 people have been relocated away from the most severely contaminated areas, 116,000 of them immediately after the accident.”
  • “An estimated five million people currently live in areas of Belarus, Russia and Ukraine that are contaminated with radionuclides due to the accident….”
  • “[M]ost recovery operation workers and those living in contaminated territories received relatively low whole body radiation doses, comparable to background radiation levels and lower than the average doses received by residents in some parts of the world having high natural background radiation levels.”
  • “As of mid-2005 … fewer than 50 deaths had been directly attributed to radiation from the disaster, almost all being highly exposed rescue workers, many who died within months of the accident but others who died as late as 2004.”
  • “About 4,000 cases of thyroid cancer, mainly in children and adolescents at the time of the accident, have resulted from the accident’s contamination and at least nine children died of thyroid cancer; however the survival rate among such cancer victims … has been almost 99%.”
  • “A total of up to 4,000 people could eventually die of radiation exposure from the Chernobyl nuclear power plant accident…. The estimated 4,000 casualties may occur during the lifetime of about 600,000 people under consideration. As about a quarter of them will eventually die from spontaneous cancer not caused by Chernobyl radiation, the radiation-induced increase of about 3% will be difficult to observe.”
  • “Because of the relatively low doses to residents of contaminated territories, no evidence or likelihood of decreased fertility has been seen among males or females. Also, because the doses were so low, there was no evidence of any effect on the number of stillbirths, adverse pregnancy outcomes, delivery complications or overall health of children.”
  • “Persistent myths and misperceptions about the threat of radiation have resulted in ‘paralyzing fatalism’ among residents of affected areas.”
  • “Poverty, ‘lifestyle’ diseases now rampant in the former Soviet Union and mental health problems pose a far greater threat to local communities than does radiation exposure.”[657]

* Per the “environment” volume of the above-cited 2006 report:

  • “Radiation from radionuclides released by the Chernobyl accident caused numerous acute adverse effects in the biota [plants and animals] located in the areas of highest exposure (i.e. up to a distance of a few tens of kilometers from the release point).”
  • Such effects included: “(a) Increased mortality of coniferous plants, soil invertebrates and mammals; (b) Reproductive losses in plants and animals; (c) Chronic radiation syndrome in animals (mammals, birds, etc.).”
  • “Beyond the CEZ [Chernobyl exclusion zone, which is 30 km or 19 miles around the site of the accident], no acute radiation induced effects on biota have been reported.”
  • “Following the natural reduction of exposure levels due to radionuclide decay and migration, populations have been recovering from the acute radiation effects.”
  • “By the next growing season after the accident, the population viability of plants and animals substantially recovered as a result of the combined effects of reproduction and immigration. A few years were needed for recovery from the major radiation induced adverse effects in plants and animals.”
  • “Both in the CEZ and beyond, different cytogenetic [cellular/genetic] anomalies attributable to radiation continue to be reported from experimental studies performed on plants and animals. Whether the observed cytogenetic anomalies have any detrimental biological significance is not known.”
  • “At present, traces of adverse radiation effects on biota can hardly be found in the near vicinity of the radiation source (a few kilometers from the damaged reactor), and on the rest of the territory, both wild plants and animals are flourishing because of the removal of the major natural stressor: humans.”[658]

* The second-largest nuclear power accident occurred in March of 2011 at the Fukushima Daiichi nuclear power facility in Japan. A 9.0-magnitude earthquake and resulting tsunami killed roughly 18,500 people, caused $220 billion in damage, and caused explosions and radiation leaks in multiple reactors at the nuclear power facility.[659] [660]

* A 2014 report about the Fukushima nuclear accident by the United Nations Scientific Committee on the Effects of Atomic Radiation found that:

  • “no radiation-related deaths or acute diseases have been observed among the workers and general public exposed to radiation from the accident.”
  • “no discernible increased incidence of radiation-related health effects are expected among exposed members of the public or their descendants.”
  • “a total of 24,832 workers were reported to have been involved in mitigation and other activities on the site and were occupationally exposed to radiation.”
  • among the workers, 16,162 received radiation doses of 10 mSv or less, 173 received doses of 100 mSv or more, and 6 received doses of 250 mSv or more (the highest dosage was 679 mSv).”[661] [662]

* The largest nuclear power plant accident in the U.S. occurred near Middletown, Pennsylvania, at the Three Mile Island nuclear facility in March of 1979.[663]

* As a result of the Three Mile Island accident, the maximum radiation dosage to local residents was less than 1 mSv.[664] [665] [666] Per the U.S. Nuclear Regulatory Commission:

In the months following the accident, although questions were raised about possible adverse effects from radiation on human, animal, and plant life in the TMI [Three Mile Island] area, none could be directly correlated to the accident. Thousands of environmental samples of air, water, milk, vegetation, soil, and foodstuffs were collected by various government agencies monitoring the area. Very low levels of radionuclides could be attributed to releases from the accident. However, comprehensive investigations and assessments by several well respected organizations, such as Columbia University and the University of Pittsburgh, have concluded that in spite of serious damage to the reactor, the actual release had negligible effects on the physical health of individuals or the environment.[667] [668]

* As of 2014, the U.S. nuclear power industry had accumulated 3,500 reactor-years of operation without any known deaths or injuries to the public.[669]

Biomass

* The term “biomass” refers to non-fossil organic materials that can be used as energy sources.[670]

* There are three main types of biomass:

  • Wood, which has traditionally been the largest source of biomass for the U.S. and the largest of all energy sources for developing nations.[671] [672] [673]
  • Biofuels, which are primarily produced from plants and used for transportation. An example of such is ethanol, which is used in cars and mainly produced from corn, sugarcane, and sugar beets.[674] [675] [676]
  • Biowaste, which are organic materials that are generally byproducts or waste products. An example of such is the methane gas that is collected from landfills and used to generate electricity and heat homes.[677] [678] [679]

* Biomass, particularly wood, was the first inanimate energy source that mankind learned to harness. Up through the Middle Ages, wood remained the primary fuel of civilization.[680]

* The world’s first internal combustion engine ran on a mixture of ethanol and turpentine refined from pine trees. The world’s first diesel engine ran on peanut oil.[681]

* In 2015, biomass supplied 4.8% of all primary energy consumed in the United States. Wood comprised 2.1 percentage points of this total, biofuels 2.2 percentage points, and biowaste 0.5 percentage point:

Biomass Energy Consumption

[682]

* In 2015, biomass supplied:

  • 7.3% of the energy consumed in the industrial sector.[683] [684]
  • 4.9% of the energy consumed in the transportation sector.[685]
  • 2.1% of the energy consumed in the residential sector.[686]
  • 0.7% of the energy consumed in the commercial sector.[687]

Biofuels

* Ethanol is the dominant biofuel in the U.S. and globally.[688] [689] [690]

* In late 1970s, the federal government began promoting domestic biofuels by subsidizing the production of domestic ethanol and placing tariffs on ethanol imports.[691]

* Federal laws passed in 2005 and 2007 mandate that increasing volumes of biofuels be used in the U.S. transportation sector through 2022.[692] [693] [694] Due primarily to these laws,[695] [696] the portion of automotive fuel that is comprised of ethanol has risen from 2.9% in 2005 to 9.9% in 2015:

Ethanol Content of Finished Gasoline

[697] [698]

* Ethanol is another name for ethyl alcohol or grain alcohol, and it is chemically identical to the intoxicating ingredient in alcoholic beverages.[699] Before shipping ethanol, producers make it unfit for human consumption by adding inedible substances to it.[700]

* Ethanol has higher octane than gasoline, which increases engine power.[701] [702]

* The energy content per unit volume of ethanol is 31% below that of gasoline, which reduces fuel economy and hence vehicle range.[703] [704] [705]

* The elemental differences between ethanol and gasoline restrict the amount of ethanol that can be used in many engines and fuel systems. As compared to gasoline, ethanol:

  • is more corrosive to certain metals.
  • erodes certain elastomers and plastics, including those sometimes used in fuel lines, gas tanks, and seals.
  • acts as a solvent that can strip away certain lubricants and coatings.
  • causes certain engines to run leaner and hotter, which can reduce engine life and catalytic converter efficacy.
  • attracts water, which can cause corrosion and permanent engine damage.[706]

* Whether or not the above effects occur depends upon the designs of engines and fuel systems, the concentrations of ethanol, exposure timeframes, and other variables such as pressure and temperature.[707]

* Federal law prohibits material changes to automotive fuels and additives without approval from the Environmental Protection Agency (EPA). In 1979, EPA approved the use of automotive fuel comprised of up to 10% ethanol by volume.[708] [709]

* In the late 2000s, a combination of the following factors created a situation in which almost all general-purpose gasoline sold in the U.S. contained 10% ethanol by volume:[710]

  • Federal mandates requiring increasing usage of biofuels.[711]
  • Federal restrictions on the amount of ethanol that can be blended with general-purpose gasoline,[712]
  • Economic malaise, vehicle efficiency increases, and other factors that suppressed the use of transportation fuels.[713] [714]

* In 2015, nearly all ethanol consumed in the U.S. was used in a fuel called E10, which is a blend of 10% ethanol and 90% gasoline.[715] [716] Per the U.S. Energy Information Administration (EIA):

  • “The saturation of the United States’ gasoline supply with ethanol sold as E10” is called the “blend wall.”[717]
  • “The term ‘blend wall’ describes the situation in the ethanol market as it nears the saturation point (at the 10 percent content level) due to limited ability to distribute or use additional ethanol….”[718]

* In response to the looming blend wall, in 2009 a coalition of ethanol producers petitioned the EPA to allow for general usage of E15, which is a blend of 15% ethanol and 85% gasoline.[719] [720]

* In 2010, EPA approved the use of E15 for model year 2007 and later general-purpose autos, and in 2011 EPA extended this approval to cars with models years of 2001 and later. However, EPA did not approve the use of E15 in older cars, heavy-duty vehicles, motorcycles, boats, lawnmowers, chainsaws, and other nonroad equipment.[721] [722] [723] Per EPA:

  • “E15 can significantly impair the emissions control technology in MY2000 [model year 2000] and older light-duty motor vehicles, heavy-duty gasoline engines and vehicles, highway and off-highway motorcycles, and all nonroad products.”
  • “ethanol enleans the A/F [air-to-fuel] ratio; this may lead to emissions products that can cause increased exhaust gas temperatures and, over time, incremental deterioration of emission control hardware and performance. Enleanment can also lead to catalyst failure.”
  • “Additionally, ethanol can cause material compatibility issues which may lead to other component failure.”[724]

* In the wake of EPA’s rulings, the following factors have limited the usage of E15:[725]

  • As of 2011, “laws and regulations in about three dozen states … restrict gasoline with more than 10% ethanol.”[726]
  • Automakers, including BMW, Chrysler, Ford, Honda, Hyundai, Kia, Mazda, Mercedes-Benz, Nissan, Toyota, Volkswagen and Volvo, have expressed varying levels of concern about possible damage from using E15 in their vehicles, including cars with models years of 2001 and later. In 2011, some of the manufacturers stated that using E15 could damage engines and void warranties.[727] [728]
  • “[M]any fuel retailers are concerned about potential liability issues if consumers misfuel their older automobiles or nonroad engines with E15.”[729] [730]
  • To dispense E15, most service stations would have to make infrastructure investments including specialized fuel tanks and/or mixing pumps.[731] [732] [733]

* Certain autos called “flex-fuel vehicles” are designed to run on wide-ranging fuel mixtures up to 85% ethanol (E85). In 2012, 4.9% of light duty automobiles could run on E85, and 1.6% of gas stations dispensed E85.[734] [735] [736]

* Due to the blend wall and other practical limitations on the usage of biofuels, the EPA used its regulatory authority to reduce the amount of biofuels required by federal law in 2014, 2015, and 2016.[737] [738]

* Federal law also mandates the usage of biofuels that produce less greenhouse gases than corn-based ethanol. One of these fuels is cellulosic biofuel, which is made from grasses, crop waste, and trees.[739] [740] [741] [742] [743]

* In 2007, when the mandate for cellulosic biofuels became law, such fuels were not being produced in commercial quantities. The law specifies how much of these fuels are to be used starting in 2010, but before the outset of each year, EPA is required to project how much this fuel will actually be produced and to relax the mandate accordingly.[744] [745]

* For 2010, EPA lowered the law’s cellulosic biofuel mandate by 94%, but none of the fuel was actually produced. For 2011, EPA lowered the mandate by 98%, but none of the fuel was produced, and EPA leveled fines of $6.8 million on motor fuel suppliers for failing to use the nonexistent fuel. For 2012, EPA lowered the mandate by 98%, but a federal appeals court struck it down because EPA had not used a “neutral methodology” to set the mandate. EPA lowered the mandate by 99% in 2013, 98% in 2014, 96% in 2015, and 95% in 2016.[746] [747] [748] [749] [750] [751]

* As opposed to petroleum and refined petroleum fuels—which are primarily transported to wholesale terminals via pipelines—ethanol is mainly transported to wholesale terminals by rail, trucks, and barges.[752] Generally, the most economical and safest way to transport liquid fuels is through pipelines,[753] but wide-ranging technical and logistical issues currently prevent most ethanol from being transported in this manner.[754] [755]

* Per EIA’s International Energy Outlook 2016, biofuel production “often depends heavily on policies or mandates to support growth.” This report projects that by 2040, biofuels will account for 7% of U.S. liquid fuels production (by volume) and 3% of global liquid fuels production.[756] [757]

Hydropower

* Hydropower is generated by harnessing the energy of moving water. Hydroelectric power plants typically channel water through turbines, thus causing them to spin and produce electricity.[758] [759] [760]

Hydropower Dam

[761]

* More than 2,000 years ago, the ancient Greeks used hydropower to grind corn, pump water, and power other types of machinery. The world’s first hydroelectric power plant was built in Appleton, Wisconsin (U.S.A.), and became operational in 1882.[762] [763] [764] [765]

* Hydropower output typically varies from year to year, because it is dependent upon rainfall and other elements of climate and weather.[766] In 2015, hydropower supplied 2.4% of all primary energy consumed in the United States:

Hydropower Energy Consumption

[767]

* In 2015, hydropower generated 6.0% of all electricity produced in the U.S.[768]

* Most large-scale hydroelectric power plants are built on rivers and use a dam to accumulate and release water. This allows the plant to generate varying amounts of electricity as the demand for electricity fluctuates.[769] [770] [771] [772]

* Large-scale hydroelectric power plants that use dams can displace surrounding residents, impede the migration of fish, modify water temperatures, and cause other changes to river ecosystems.[773] [774] [775] [776]

* Per the U.S. Energy Information Administration’s Office of Energy Efficiency & Renewable Energy:

Research and development efforts have succeeded in reducing many of these environmental impacts through the use of fish ladders (to aid fish migration), fish screens, new turbine designs, and reservoir aeration.[777]

* Roughly 2-3% of the dams in the U.S. are used to generate hydropower. The rest are primarily used for recreation (35%), fish stock/farm ponds (18%), flood control (15%), public water supply (12%), irrigation (11%), and other uses (7%).[778] [779] [780]

* A 2012 analysis by Oak Ridge National Laboratory estimated that the U.S. could increase its hydropower generation by 15% through adding hydroelectric generators to existing non-powered dams [NPDs]. The analysis “did not consider the economic feasibility of developing each unpowered facility” but noted that:

many of the monetary costs and environmental impacts of dam construction have already been incurred at NPDs, so adding power to the existing dam structure can often be achieved at lower cost, with less risk, and in a shorter timeframe than development requiring new dam construction.[781]

* Hydroelectric power can also be produced without dams by “run-of-the-river” generators, which temporarily divert a portion of the river through canals or pipes that flow through turbines.[782]

* A 2006 analysis by Idaho National Laboratory estimated that U.S. rivers and streams have an average hydropower potential of 297,436 megawatts. The analysis also estimated that:

  • 8% of this total potential is being harnessed.
  • 33% of this total potential cannot be developed because of environmental and land use restrictions, lack of accessibility, or because it is located large distances from electrical power grids.
  • 33% of this total potential could feasibly be developed.
  • 8% of this total potential could be harnessed without using dams.
  • 4% of this total potential could be harnessed without using dams and without using sites that have low-power potential, which makes them economically unattractive.[783] [784]

Wind

* Wind power is harnessed by converting the energy of natural air movements into mechanical energy used to drive electric power generators, pumps, and mills.[785]

Wind Turbine

[786]

* More than 2,000 years ago, the Chinese used windmills to pump water. Around 600 A.D., Persians used windmills to grind grain.[787]

* From 1998 through 2015, the portion of U.S. primary energy supplied by wind grew from 0.03% to 1.9%:

Wind Energy Consumption

[788]

* In 2015, wind generated 4.7% of all electricity produced in the U.S.[789]

* Ideally, commercial wind turbines should be located:

  • where average wind speeds are at least 13 miles per hour.
  • within short distances of electrical power grids.
  • far enough away from humans to avoid noise pollution.
  • in places with limited bird traffic.[790] [791] [792] [793] [794]

* Wind speeds fluctuate on an hourly, daily, monthly, and seasonal basis. In wind-rich areas, winds are sometimes not strong enough to drive turbines for days at a time.[795] [796] [797] Per the U.S. Energy Information Administration (EIA):

Even at the best sites, there are times when the wind does not blow sufficiently and no electricity is generated.[798]
Wind generators are subject to abrupt changes in wind speed, and their power output is characterized by steep ramps up or down.[799]

* Power capacity (a commonly cited statistic for wind energy installations[800]) is the amount of electricity that wind turbines produce when operating at full capacity, which occurs when wind conditions are optimal. It is not a measure of actual production.[801] [802] In the U.S. during 2004–2014, actual production from wind turbines was 29% of their power capacity.[803]

* With the exception of pumped hydropower, current technology cannot economically store large quantities of electricity. Thus, utilities must produce enough electricity to meet their customers’ demands on a second-by-second basis.[804] [805] [806] [807] [808] [809] [810]

* Because wind power is intermittent and utility-scale electricity cannot be easily stored, most wind power capacity must be backed-up by other energy sources that can generate electricity on demand, such as natural gas power plants.[811] [812] [813] [814] [815] [816] Per EIA:

Often, wind generation does not coincide with the demand for electric power; wind resources are generally more prevalent overnight, when demand for electric power is at a minimum. In most areas, summer peak demand for electricity coincides with hot afternoons when consumers have turned up their air conditioners – but in many areas, such times are calm and wind resources may be quite low.[817] [818]

* As the amount of wind capacity rises in a given region, so do the challenges and costs of backing up its intermittent energy output.[819] [820] [821] [822]

Solar

* Solar power is harnessed by converting electromagnetic energy from the sun into heat or electricity. The current primary solar energy technologies include:

  • thermal collectors, which capture sunlight and covert it to heat that can be used to warm items such as indoor air, tap water, and swimming pools.
  • concentrating power systems, which use mirrors to focus sunlight in order to heat liquids that power electricity-generating steam turbines.
  • photovoltaic (PV) cells, which use layers of semi-conductive materials (like silicon) to convert sunlight directly into electricity.[823] [824] [825] [826]

* In the third century B.C., Greeks and Romans used mirrors to concentrate solar energy for the purpose of lighting torches. In the late 1800s, a French mathematician built the world’s first solar-powered steam engine.[827]

* In 1953, three U.S. scientists built the world’s first silicon photovoltaic cell. This was the first photovoltaic cell that generated enough energy to power common electrical devices. One year later, Western Electric began selling commercial licenses for silicon photovoltaic technologies.[828]

* With the exception of nuclear and geothermal power, all major current energy sources ultimately derive from solar energy. Wind energy arises from sunlight heating the atmosphere, biofuels and fossil fuels are made of organic materials that were nourished by sunlight, and hydropower is driven by the hydrological cycle, which is powered by the sun.[829] [830] [831] [832]

* From 1988 through 2015, the portion of U.S. primary energy supplied by solar power grew from 0.0001% to 0.5%:

Solar Energy Consumption

[833]

* In 2015, solar energy produced 0.9% of all electricity generated in the U.S.[834]

* From 1998-2011, the average reported installed price for residential and commercial PV systems declined by about 5-7% per year. Primarily, this was due to technological advancements, economies of scale, and federal, state and local government subsidies.[835] [836] [837] [838] [839] [840]

* In 2009, Jeffrey Punton of Rochester, N.Y., installed 20 solar panels at his home for a cost of $42,480. The federal government and state of New York paid for $29,504 or 69% of these costs.[841] Per a 2012 report by Lawrence Berkeley National Laboratory:

The market for PV in the United States is, to a significant extent, driven by national, state, and local government incentives, including up-front cash rebates, production-based incentives, renewables portfolio standards, and federal and state tax benefits.[842]

* Power capacity (a commonly cited statistic for solar energy installations[843]) is the amount of electricity that solar systems produce when operating at full capacity, which occurs when the sun is directly overhead, the solar panels are perpendicular to the sunlight, the sky is clear, and temperatures are low. It is not a measure of actual production.[844] [845] [846] In the U.S. during 2004–2014, actual production from utility-scale solar systems was 17% of their power capacity.[847]

* With the exception of pumped hydropower, current technology cannot economically store large quantities of electricity. Thus, utilities must produce enough electricity to meet their customers’ demands on a second-by-second basis.[848] [849] [850] [851] [852] [853] [854]

* Because solar power is intermittent and utility-scale electricity cannot be easily stored, most solar power capacity must be backed-up by other energy sources that can generate electricity on demand, such as natural gas power plants.[855] [856] [857] [858] [859]

* As the amount of solar capacity rises in a given region, so do the costs of backing up its intermittent energy output.[860] [861]

Geothermal

* Geothermal energy is harnessed by transferring heat from or to the earth. The current main geothermal technologies include:

  • district heating systems, which heat buildings by piping in water from hot springs and reservoirs.
  • power plants, which generate electricity through steam turbines that are powered by steam or superheated water typically piped in from a mile or two beneath the surface of the earth.
  • heat pumps, which cool and heat buildings by transferring heat to and from the ground. In most places, the temperature of the earth at 10 feet underground stays between 50-60°F throughout the year. In the summer, heat pumps cool buildings by transferring their heat into the ground. In winter, heat pumps warm buildings by transferring heat from the ground into the buildings.[862] [863] [864] [865] [866]

* Since ancient times, people have used hot springs for bathing, cooking, and heating.[867]

* The world’s first electricity-generating geothermal plant was built in 1904 in Tuscany, Italy.[868]

* From 1980 through 2015, the portion of U.S. primary energy supplied by geothermal power grew from 0.07% to 0.23%:

Geothermal Energy Consumption

[869]

* In 2015, geothermal generated 0.4% of all electricity produced in the U.S.[870]

* Electricity-generating geothermal plants are typically built at sites where geothermal reservoirs are not buried too deeply. In the U.S., such resources are mostly in the western states and Hawaii.[871] [872]

Public Policies

Competing Objectives

* Choosing between different forms of energy often involves tradeoffs between competing objectives, such as affordability, environmental impacts, and energy security. These tradeoffs can sometimes be impossible to objectively quantify.[873] [874] [875] [876] [877]

* A 2008 Harris poll of 1,020 U.S. adults found that 92% favored “a large increase in the number of wind farms.”[878] The same poll found that among 787 U.S. adults who pay household energy bills:

  • 40% were not willing to pay anything more for energy from renewable sources.
  • 48% were willing to pay at least 5% more.
  • 31% were willing to pay at least 10% more.
  • 14% were willing to pay at least 15% more.
  • 7% were willing to pay at least 20% more.
  • 3% were willing to pay at least 30% more.
  • 1% were willing to pay at least 40% more.[879]

* In 2015, the U.S. Energy Information Administration (EIA) projected that the levelized cost of electricity generated by new onshore wind power in 2020 will be 1% higher than that from advanced combined cycle natural gas [Adv CC], and the cost of photovoltaic [PV] solar will be 73% higher than Adv CC.[880] Per EIA, these levelized costs “significantly understate the advantage of Adv CC relative to onshore wind … while overstating the advantage of Adv CC relative to solar PV….”[881] See the section above on the costs of electricity for extensive details about comparing the costs of electricity generating technologies.

* A 2010 Rasmussen poll of 1,000 likely voters found that:

  • 56% were not willing to pay more taxes or higher utility costs to “generate cleaner energy and fight global warming.”
  • 37% were willing to pay at least $100 more per year.
  • 18% were willing to pay at least $300 more per year.
  • 8% were willing to pay at least $500 more per year.
  • 5% were willing to pay at least $1,000 more per year.
  • 2% were willing to pay in excess of $1,000 more per year.[882]

* During 2015, the average cost of ethanol without federal subsidies was 38% higher than gasoline, and the average cost of biodiesel without federal subsidies was 118% higher than gasoline.[883]

* Per a 1992 EIA report:

Much current debate on energy policy focuses on externalities associated with energy use. Many believe there is a large implicit subsidy to energy production and consumption insofar as pollution results in environmental costs not fully charged to those responsible. …
 
In fact, the effort to deal with environmental concerns has become a central feature of Federal energy policy. Substantial costs which were formerly outside the market mechanism have, through the implementation of a series of taxes and regulations, been internalized to energy markets.[884]

Subsidies

* “Subsidies,” as defined by the U.S. Government Accountability Office, are “payments or benefits provided to encourage certain desired activities or behaviors.”[885] Per the U.S. Energy Information Administration (EIA), subsidies “stimulate the production or consumption of a commodity over what it would otherwise have been.”[886]

* EIA classifies government energy subsidies into two main categories: direct and indirect. Direct subsidies have explicit effects on government budgets, while indirect subsidies do not. For instance, tax breaks for the production of certain energy products are direct subsidies because they produce readily identifiable changes in tax revenues. In contrast, government mandates that require the use of certain energy products are indirect subsidies because the effects don’t appear as line items in government budgets, but they still impact energy consumers and producers.[887] [888] [889]

* Reasons provided for enacting energy subsidies include but are not limited to:

  • promoting forms of energy that create less pollution or greenhouse gases.[890] [891]
  • correcting for the “energy paradox,” an “empirical observation that consumers require an abnormally high rate of return to undertake energy-efficiency investments.”[892]
  • increasing the stability of a nation’s energy supply by promoting domestic sources of energy over those controlled by hostile or unstable foreign governments.[893] [894]
  • paying energy bills for low-income households.[895]

* Ancillary consequences of government energy subsidies include but are not limited to:

  • increased energy costs,[896] [897] [898] [899] which reduce economic growth and leave people with less money “to satisfy basic needs for food, shelter, clothing, education, and health.”[900] [901]
  • increased energy consumption caused by lowering the price of energy at the point of sale (though not necessarily the overall cost), which decreases consumers’ incentive to conserve energy.[902] [903] [904]
  • increased food prices that augment hunger, particularly in poor nations.[905] [906] [907]
  • increased emissions of certain pollutants.[908]
  • increased taxes and/or government debts that exceed the benefits of the subsidies.[909] [910] [911] [912]
  • the government “paying firms or households to make choices about investment, production, or consumption that they would have made without the subsidies. For example, tax credits for energy-efficient windows might go to homeowners who would have purchased them anyway.”[913]
  • guaranteeing corporations double-digit profits on certain energy projects,[914] transferring the risks of their investments to the public,[915] and supplying them with funds used for executive bonuses shortly before they declare bankruptcy.[916]

* Forms of energy subsidies include but are not limited to:

  • giving money to producers and consumers of certain energy products.[917] [918]
  • offering preferential tax treatments to producers and consumers of certain energy products.[919] [920]
  • mandating that consumers and producers use specified amounts of certain energy products.[921] [922] [923] [924]
  • purchasing through government agencies certain energy products that are significantly more expensive than other alternatives.[925] [926]
  • providing loans for energy projects that are unable to obtain private financing due to the risk of default, or guaranteeing to pay the loans in the event of default.[927] [928]
  • spending money on research and development for certain energy products.[929] [930]

* Examples of subsidies for:

  • coal include direct federal subsidies totaling $1.4 billion in 2010, with 49% of this going to the U.S. Department of Energy to conduct research primarily aimed at reducing greenhouse gas emissions.[931] [932] [933] Another 41% of these subsidies were for tax preferences, with 61% of this going to clean coal facilities and pollution control equipment.[934]
  • renewables in general include 679 federal initiatives that support solar, wind, biofuel, geothermal, hydropower, ocean, or waste conversion energy.[935] In 2010, direct federal subsidies for renewables amounted to $14.7 billion.[936] As an example of an indirect subsidy, thirty states and the District of Columbia require utilities to generate or obtain specified portions of their electricity from renewable sources.[937]
  • solar include direct federal subsidies including cash grants, tax preferences, research and development [R&D] expenses, and loan guarantees totaling $1.1 billion in 2010.[938] The states of California and Arizona have forced utilities to purchase electricity from customers with solar panels at rates that don’t account for the transmission or distribution costs of this energy. This pushes these costs, which amount to about 40% of the typical electricity bill, onto other customers.[939] [940] [941] [942] [943]
  • wind include direct federal subsidies totaling $5.0 billion in 2010, with 97% of this coming from the American Recovery and Reinvestment Act of 2009 (a.k.a. Obama stimulus).[944] The most prominent of these subsidies is a renewable energy tax credit/grant that is twice as high for wind, geothermal, and certain biofuels than it is for other renewable energy sources.[945] [946] [947]
  • biofuels include the EPA’s Renewable Fuel Standard program, which “generally requires the volume of biofuels used in the transportation sector … to increase through 2022 to an annual total of 36 billion gallons.”[948] (For a point of reference, the U.S. transportation sector consumed 99 billion gallons of gasoline in 2009.[949]) This subsidy was enacted to “encourage the domestic production of ethanol and other biofuels” and to reduce “greenhouse-gas emissions from the transportation sector.”[950]
  • natural gas and petroleum include direct federal subsidies totaling $2.8 billion in 2010, with 95% of this coming from tax preferences.[951] The largest of these (comprising 36% of the preferences) is called “percentage depletion,” a tax break on properties mined for natural resources such as oil, gas, coal, minerals, uranium, and geothermal steam. Since 1975, major oil and gas companies have been excluded from this tax preference, and the primary beneficiaries are small independent companies and property owners. The purpose of this subsidy is to maximize the yield of resources from each property.[952] [953] [954] [955] [956]
  • energy conservation/efficiency include direct federal subsidies totaling $6.6 billion in 2010, with 51% this going to cash payments and 49% to tax preferences. The largest of these (comprising 48% of total subsidies) is a tax preference for installing energy-efficient windows, furnaces, boilers, roofs, doors, etc. in existing homes.[957]
  • nuclear include direct federal subsidies totaling $2.5 billion in 2010, with 47% of this going to R&D. Of these R&D subsidies, the largest item (comprising 34% of total R&D subsidies) is for the environmental cleanup of government-sponsored nuclear research facilities. Although EIA classifies the environmental cleanup of “nuclear weapons development and government-sponsored nuclear energy research” facilities as subsidies for “non-defense environmental cleanup,” EIA has explained that these are not subsidies in the true sense of the word.[958] [959] [960] [961]

* As of May 2016, neither EIA nor the Congressional Budget Office (CBO) has published annual historical data providing a comprehensive and consistent measure of direct federal energy subsidies.[962] [963] [964] [965] EIA has published such data for certain years, although the level of detail varies, and definitions of what constitutes direct subsidies are not always consistent.[966] CBO has published data on federal energy-related tax preferences going back to 1977. These EIA and CBO data are reviewed below. They do not account for:

  • state and local subsidies.
  • federal indirect subsidies, such as mandates that force energy producers and consumers to use specified amounts of certain energy products, and federal agencies that purchase certain energy products that are more expensive than other alternatives.
  • federal tax preferences that are generally available to wide-ranging industries.
  • federal energy subsidies that have negligible value.[967] [968] [969] [970]

* Per EIA, energy subsidies in the range of one percent of total energy sales are “in general, too small to have a significant effect on the overall level of energy prices and consumption in the United States.”[971] Likewise, per EIA, “market impacts are negligible” for “programs that offer small subsidies for products for which there are huge existing markets….”[972]

Year

Direct Federal Energy Subsidies as

a Portion of Total Energy Sales

1990[973]

1-2%

1999[974]

0.7%

2007[975]

1.4%

2010[976]

3.1%

2013[977]

2.1%

* Energy tax preferences, unlike R&D subsidies, are “directly linked” to energy production, consumption or conservation, and individuals and corporations must take “specified actions” to receive these subsides.[978] [979]

* From 1985 through 2015, inflation-adjusted federal tax preferences for:

  • fossil fuels averaged $3.9 billion per year.
  • renewables averaged $4.4 billion per year.
  • energy efficiency averaged $1.2 billion per year.
  • nuclear averaged $0.3 billion per year.[980]
Energy-Related Federal Tax Preferences

[981]

* Per EIA, “some forms of energy receive subsidies that are substantial relative to” the energy they produce, and thus, a “per-unit measure” of energy subsidies “may provide a better indicator of its market impact than an absolute measure.”[982] [983] For example, in 2010, coal received federal electricity production subsidies totaling $1,189 million, while solar received $968 billion.[984] However, coal produced 44.9% of the nation’s electricity, and solar produced 0.1%.[985] [986]

* From 1985 through 2015, federal tax preferences per unit of primary energy production for:

  • renewables averaged $563 per billion BTUs.
  • fossil fuels averaged $67 per billion BTUs.
  • nuclear averaged $38 per billion BTUs.[987]
Energy-Related Federal Tax Preferences
Energy-Related Federal Tax Preferences per Unit of Production

[988]

* Aggregating energy subsidies into broad categories (like fossil fuels and renewables) can obscure their nature, because specific components of these broad categories sometimes receive relatively large portions of the subsidies. Per EIA, federal energy subsidies are often “targeted at narrow segments of the energy industry” and provide “relatively large payments to producers using specific energy technologies that otherwise would be uneconomical.”[989] [990] For example:

  • Under a previous federal subsidy enacted to ease dependence on foreign oil, “institutional investors such as insurance companies, banks, utilities, and large corporations with substantial net revenues” reduced their tax burdens by billions of dollars through a tax preference for “synthetic coal.” When this subsidy ended in 2007, “none of the 59 coal synthetic plants … remained profitable and all ceased production at the end of 2007.”[991] [992] [993] [994] [995]
  • In 2012, the U.S. Navy procured 450,000 gallons of biofuels for its “Great Green Fleet” program. These fuels (made from used cooking oil and algae) cost $26.75 per gallon, while conventional fuel cost $3.60 per gallon.[996] [997] [998] [999]
  • In 2010, hydropower received 3% of all renewable electricity subsidies while producing 60% of all renewable electricity. In comparison, wind received 76% of all renewable electricity subsidies while producing 22% all renewable electricity, and solar received 15% of all renewable electricity subsidies while producing 0.6% of all renewable electricity.[1000]

* EIA has published comprehensive accountings of direct federal energy subsides for 1992, 1999, 2007, 2010, and 2013. Only the last three of these accountings disaggregate subsidies for specific renewables, like wind, solar, and biofuels.[1001] [1002] [1003] [1004] [1005] Combining this data with EIA’s primary energy production data reveals the following levels of per-unit energy subsidies:

Direct Energy Subsidies per Unit of Production

[1006]

* Per EIA, there can be considerable lag times between subsidies and their effects on energy production. Thus, subsidies divided by production in any given year are not always representative of the larger picture. For example, many subsidies during 2007-2010 were provided to facilities still under construction as of 2011. Also, subsidies for research and development (R&D) of new technologies can take “many years” to yield results.[1007] However, EIA has noted that the outcomes of R&D subsidies are “inherently uncertain,” and:

  • “Several studies suggest that the return on overall Federal R&D investment is much lower than the return on private-sector R&D, implying relatively high failure rates.”
  • “Much of what is defined as energy R&D in the Federal government’s budget accounts is not directly expended on energy research or development. Rather, a portion of the funds are expended on environmental restoration and waste management associated with the byproducts of energy-related research facilities, e.g., nuclear waste disposal.” (Note that such subsidies are for government facilities; the owners of commercial nuclear power plants must pay for nuclear waste disposal.[1008] [1009])
  • “The creation of a Federally-funded R&D program could, under some circumstances, displace private-sector R&D. In that case, the Federal program would not produce new knowledge that could not be developed by the private sector, but would simply reduce private R&D costs.”[1010] [1011] [1012] [1013] [1014] [1015]

Taxes

* From 2007 to 2012, companies in the S.&P. 500 paid an average of 29% in federal, state, local, and foreign corporate income taxes.[1016] [1017] Among large oil companies in the S.&P. 500, the average corporate income tax rate was 37%.[1018]

* The burden of corporate income taxes falls upon: (1) business owners in the form of decreased profits, (2) workers in the form of reduced wages, and (3) possibly consumers in the form of higher prices.[1019] [1020]

* The Congressional Budget Office (CBO) estimates that 75% of corporate income taxes are borne by owners/stockholders and 25% are borne by workers.[1021] Other creditable sources estimate that owners/stockholders bear anywhere from 33% to 100% of this tax burden.[1022] For more detail, see Just Facts’ research on tax distribution.


* Excise taxes are similar to sales taxes, except that they are imposed on specific goods and services.[1023] [1024]

* In addition to raising government revenue, excise taxes are sometimes levied to discourage or penalize certain activities.[1025] [1026] [1027] Per the U.S. Energy Information Administration:

Energy excise taxes are disincentives to the production and consumption of the fuels on which they are levied. Excise taxes increase fuel prices and reduce volumes consumed.[1028]

* In 2016, federal and state excise taxes on gasoline averaged 39 cents per gallon.[1029]

* In 2003, the federal government collected about $35 billion in energy-related excise taxes.[1030] This equates to 5% of all energy expenditures in the U.S. that year.[1031]

* The economic burden of excise taxes primarily falls on retail customers in the form of higher prices. Per the Congressional Budget Office:

The effect of excise taxes, relative to income, is greatest for lower-income households, which tend to spend a greater proportion of their income on such goods as gasoline, alcohol, and tobacco, which are subject to excise taxes.[1032] [1033] [1034] [1035]

* To reduce greenhouse gases, government officials and scientists have proposed increasing taxes on electricity,[1036] gasoline,[1037] crude oil,[1038] steel and aluminum,[1039] flying and driving,[1040] [1041] or any activity that emits carbon dioxide.[1042]


Regulations

* Per the U.S. Energy Information Administration (EIA):

  • “The regulation of energy markets can have the same consequences for energy prices, production, and consumption as the direct payment of a cash subsidy or the imposition of a tax.”
  • “Regulation is the most consequential form of federal intervention in the energy industries. … Many of these interventions are designed to yield environmental benefits.”
  • “Regulations more often explicitly penalize rather than subsidize the targeted fuel.”
  • “There are so many Government regulations concerning energy that it is difficult to identify and analyze all of them.”[1043]

* Regulatory costs for hydroelectric power plants increased from 5% of the total costs of generating hydroelectricity in 1980 to 25-30% of the costs in 2010.[1044] [1045] [1046]

* Regulations on the sulfur content of diesel fuel have played a role in raising the price of diesel above that of gasoline.[1047]

* Regulation of hydropower plants has sometimes reduced output from wind farms.[1048]

* During a January 2008 interview with the San Francisco Chronicle, Barack Obama stated:

Let me sort of describe my overall policy. What I’ve said is that we would put a [greenhouse gas] cap-and-trade system in place that is as aggressive, if not more aggressive, than anybody else’s out there. …
 
[U]nder my plan of a cap and trade system, electricity rates would necessarily skyrocket, regardless of what I say about whether coal is good or bad, because I’m capping greenhouse gasses: coal power plants, natural gas, you name it, whatever the plants were, whatever the industry was, they would have to retrofit their operations. That will cost money. They will pass that money on to consumers.[1049]

* In June of 2009, the U.S. House of Representatives passed a bill that would have capped most sources of greenhouse gas emissions in the U.S. at 17% below 2005 levels by 2020 and at 83% below 2005 levels by 2050.[1050] This bill passed the House by a vote of 219-212, with 82% of Democrats voting for it and 94% of Republicans voting against it.[1051] The bill was then forwarded to the Senate and never voted upon.[1052]

* In December of 2009, the Obama administration Environmental Protection Agency (EPA) issued a finding that greenhouse gases “threaten the public health and welfare of current and future generations.” This finding allows the EPA to regulate greenhouse gases under the Clean Air Act.[1053] [1054]

* In May of 2013, the Obama administration made a regulatory decision that a metric ton of carbon dioxide (CO2) has a “social cost” of $38. This figure is used by EPA and other agencies under the authority of the President to assess and justify regulations on greenhouse gases.[1055] [1056] [1057]

* Per EIA projections made in 2013, a CO2 tax of $25 per metric ton that begins in 2014 and grows to $37 in 2022 would increase gasoline prices by 11% and electricity prices by 30% in 2022. These increases are relative to a situation in which no government greenhouse gas reduction policies are enacted and “market investment decisions are not altered in anticipation of such a policy.”[1058]

* The U.S. Department of the Interior (DOI), which is under the authority of the President, manages 500 million acres or about one fifth of all U.S. surface land and more than three times as much acreage in offshore areas. DOI leases some of these lands for energy projects such as oil drilling and solar energy facilities.[1059] [1060] [1061]

* From 2003 through 2014, energy from fossil fuels produced on federal and American Indian lands declined by 20%, and the portion of U.S. energy from fossil fuels produced on these lands declined by 35%:

Fossil Fuels Produced on Federal, Indian Lands

[1062]

* A 2013 paper in the journal Wildlife Society Bulletin estimated that 888,000 bats and 573,000 birds are killed each year by wind turbines in the U.S. Approximately 83,000 of the bird fatalities are raptors such as hawks, eagles, owls and falcons, which are protected under federal and state laws.[1063] [1064]

* An investigation published by the Associated Press in May 2014 found that:

  • wind farms in Converse County, Wyoming, “have killed more than four dozen golden eagles since 2009….”
  • “The Obama administration has charged oil companies for drowning birds in their waste pits, and power companies for electrocuting birds on power lines. But the administration has never fined or prosecuted a wind-energy company, even those that flout the law repeatedly.”
  • “Getting precise figures is impossible because many companies aren’t required to disclose how many birds they kill. … When companies voluntarily report deaths, the Obama administration in many cases refuses to make the information public….”[1065]

* In November 2013, the Associated Press reported that the Obama administration:

for the first time has enforced environmental laws protecting birds against wind energy facilities, winning a $1 million settlement from a power company that pleaded guilty to killing 14 eagles and 149 other birds at two Wyoming wind farms.[1066]

* In December of 2013, the Obama administration issued a regulation that allows it to give permits to wind farms to accidentally kill eagles for periods of up to 30 years.[1067]

* In June 2014, the Obama administration gave a permit to a California wind farm that allows it to kill up to five golden eagles over five years.[1068]


Fracking

* Some natural gas and oil resources are located in semi-porous or non-porous rocks that don’t allow the fuel to freely flow when accessed through drilling. Such fuels are often found in shale formations and are referred to as “tight oil” and “tight gas.” These resources can be extracted by using a combination of technologies known as horizontal drilling and hydraulic fracturing.[1069] [1070] [1071] [1072]

* Horizontal drilling involves penetrating the ground vertically (like traditional drilling) and then turning horizontally in order to drill along the layer that contains the fossil fuel resources. This method of drilling exposes more of the fossil fuel resources to the bore of each well, thus increasing yields and decreasing the surface footprint of drilling operations.[1073] [1074]

Horizontal Drilling

[1075]

* Horizontal drilling was first successfully employed in 1929 and has been used commercially since the late 1980s. By 1990, more than 1,000 horizontal wells were drilled worldwide, almost all for the purpose of extracting crude oil.[1076]

* Hydraulic fracturing or fracking involves injecting fluids at high pressures from the bore of a well into the layer that contains the fossil fuel resources. This process creates fractures in the rock, which allows the fuels to flow to the bore of the well. The fluids used for fracking typically contain sand or ceramic beads that serve to hold open the fractures after they have been created. This fluid also contains varying chemicals that are used for purposes such as preventing pipe corrosion.[1077] [1078] (A detailed description of the process is shown in the video below.)

* Hydraulic fracturing was first successfully employed to drill for oil in 1947 and has been used commercially since the 1950s. By 1955, more than 100,000 fracking treatments were performed. In the 1980s and early 1990s, Texas oilman George Mitchell refined the process of fracking to extract natural gas from shale in a cost-effective manner.[1079]

* In the early 2000s, horizontal drilling coupled with hydraulic fracturing became widely used to extract tight gas. In the mid-2000s, the combination of these technologies also became widely used to extract tight oil.[1080] [1081] [1082] The process for extracting natural gas is shown in this video:

* From 2005 to 2015, U.S. natural gas production increased by 50%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in shale formations.[1083] [1084] [1085] [1086]

* In 2016, the U.S. Energy Information Administration reported that fracking:

  • has “allowed the United States to increase its oil production faster than at any time in its history.”
  • now produces “about half of total U.S. crude oil production.”[1087]

* Per a 2012 U.S. Government Accountability Office (GAO) report:

[A]ccording to a number of studies and publications GAO reviewed, shale oil and gas development poses risks to air quality, generally as the result of (1) engine exhaust from increased truck traffic, (2) emissions from diesel-powered pumps used to power equipment, (3) gas that is flared (burned) or vented (released directly into the atmosphere) for operational reasons, and (4) unintentional emissions of pollutants from faulty equipment or impoundments—temporary storage areas. Similarly, a number of studies and publications GAO reviewed indicate that shale oil and gas development poses risks to water quality from contamination of surface water and groundwater as a result of erosion from ground disturbances, spills and releases of chemicals and other fluids, or underground migration of gases and chemicals.
 
The risks identified in the studies and publications we reviewed cannot, at present, be quantified, and the magnitude of potential adverse affects or likelihood of occurrence cannot be determined for several reasons. First, it is difficult to predict how many or where shale oil and gas wells may be constructed. Second, the extent to which operators use effective best management practices to mitigate risk may vary. Third, based on the studies we reviewed, there are relatively few studies that are based on comparing predevelopment conditions to postdevelopment conditions—making it difficult to detect or attribute adverse conditions to shale oil and gas development.[1088]

* The primary concern about fracking is that the fuels it releases from tight formations will migrate to the surface of the earth and contaminate wells and other bodies of water.[1089]

* In areas that are rich in petroleum and natural gas (methane), these fuels commonly seep up to ground level through natural processes:

  • Per the Institute for Plasma Physics in the Netherlands: “In 1859, the first petroleum was pumped out of the ground in Pennsylvania in the USA. For long the petroleum had been a nuisance, contaminating wells for drinking water.”[1090]
  • Per the U.S. Geological Survey: “Reports from the 1800’s document [methane] gas bubbles in water wells, in streams, and in fields after heavy rains; this evidence suggests that migration has always existed.”[1091]
  • Per a 2007 academic textbook The Chemistry and Technology of Petroleum: “Most of the crude oil currently recovered is produced from underground reservoirs. However, surface seepage of crude oil and natural gas are common in many regions.”[1092]
  • Per the Encyclopædia Britannica: “The first discoveries of natural gas seeps were made in Iran between 6000 and 2000 BC. Many early writers described the natural petroleum seeps in the Middle East, especially in the Baku region of what is now Azerbaijan.”[1093]
  • Per the Kentucky Department for Environmental Protection: “Water wells located in pump houses, well pits, basements or any enclosed structure should be properly vented as a safety precaution to prevent the buildup of methane. … Naturally occurring gases, such as methane and hydrogen sulfide, may be present in some wells. These gases occur naturally in the subsurface, accumulating in voids within the rock and as dissolved gas in groundwater.”[1094]
  • Per GAO: “Methane can occur naturally in shallow bedrock and unconsolidated sediments and has been known to naturally seep to the surface and contaminate water supplies, including water wells.”[1095]

* Because methane is odorless, invisible, and generally nontoxic, people who have naturally occurring methane in their wells may be unaware of it until they test for it.[1096] [1097]

* Fracking is typically performed at depths of 6,000 to 10,000 feet, and the fractures can extend for several hundred feet. Drinking water is commonly located at depths of less than 1,000 feet.[1098]

* As with conventional drilling and other industrial processes (including biofuel production), in cases of accidents and negligence, fracking can and has caused gas leaks, contaminant spills, and other environmental damage.[1099] [1100]

* In May of 2011, Lisa Jackson, head of the Obama administration EPA stated: “I’m not aware of any proven case where the fracking process itself affected water, although there are investigations ongoing.”[1101]

* A 2012 GAO evaluation of three major studies and a series of interviews with regulatory officials in eight states found no proven cases where groundwater contamination was caused by properly conducted fracking. However, GAO noted that:

the widespread development of shale oil and gas is relatively new. As such, little data exist on (1) fracture growth in shale formations following multistage hydraulic fracturing over an extended time period, (2) the frequency with which refracturing of horizontal wells may occur, (3) the effect of refracturing on fracture growth over time, and (4) the likelihood of adverse effects on drinking water aquifers from a large number of hydraulically fractured wells in close proximity to each other.[1102]

* In 2014, the U.S. Department of Energy published the results of an investigation to determine if natural gas or fracking fluids had migrated upward to an underground gas field that is “1,300 feet below the deepest known groundwater aquifer” at six fracking wells in Greene County, Pennsylvania. The study found there was “no detectable migration of gas or aqueous fluids” to the gas field.[1103]

Footnotes

[1] Entry: “energy.” Oxford Dictionary of Biochemistry and Molecular Biology. Oxford University Press, 1997.

Page 207: “the capacity of a system for doing work.” There are various forms of energy – potential, kinetic, electrical, chemical, nuclear, and radiant – which can be interconverted by suitable means.”

[2] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 2: “Energy appears in many forms, such as motion, heat, light, chemical bonds, and electricity. If you have studied physics, you may know that even mass is a form of energy. We say that energy is present in energy sources, like wood, wind, food, gas, coal, and oil. All these different forms of energy have one thing in common - that we can use them to accomplish something we want. We use energy to set things in motion, to change temperatures, and to make light and sound. So we may say: Energy is the capacity to do useful work.

[3] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Energy: The capacity for doing work as measured by the capability of doing work (potential energy) or the conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are easily convertible and can be changed to another form useful for work. Most of the world’s convertible energy comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical or other means in order to accomplish tasks. Electric energy is usually measured in kilowatthours, while heat energy is usually measured in British thermal units.

[4] Book: Applied Energy: An Introduction. By Mohammad Omar Abdullah. CRC Press, 2013.

Page 1: “Generally, energy forms are either potential or kinetic. Potential energy comes in forms that are stored including chemical, gravitational, mechanical, and nuclear energy. Kinetic energy forms are used for doing a variety of work, for instance, electrical, chemical, electrochemical energy, thermal (heat), electromagnetic (light), motion, and vibration (sound energy).”

[5] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

British Thermal Unit (Btu): The quantity of heat required to raise the temperature of 1 pound of liquid water by 1 degree Fahrenheit at the temperature at which water has its greatest density (approximately 39 degrees Fahrenheit). …

Btu Conversion Factor: A factor for converting energy data between one unit of measurement and British thermal units (Btu). Btu conversion factors are generally used to convert energy data from physical units of measure (such as barrels, cubic feet, or short tons) into the energy-equivalent measure of Btu. (See <www.eia.gov>

[6] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 14: “Energy is measured in joules (J), and 1 joule is the amount of energy needed to lift a mass of a hundred grams over one meter. So, if you lift an apple one meter, you need one joule of energy to do it. And we can go on: for two meters, you need 2 joules, and to lift 1 kg 1 meter, you need 10 joules. … All forms of energy can be expressed in joules. For example, when one litre of petrol is burned, it releases 28 MJ of energy.”

[7] Book: Physics. By David Halliday and Robert Resnick. John Wiley & Sons, 1978.

Page 151: “Energy may be transformed from one kind to another, but it cannot be created or destroyed; the total energy is constant. This statement is a generalization from our experience, so far not contradicted by observation of nature. … The energy concept now permeates all of physical science and has become one of the unifying ideas of physics.”

Page 154: “Einstein wrote: ‘Pre-relativity physics contains two conservation laws of fundamental importance, namely the law of conservation of energy and the law of conservation of mass; these two appear as completely independent of each other. Through relativity theory they melt together into one principle.’

[8] Book: Physics: The Easy Way (Third edition). By Robert L. Lehrman. Barron’s Educational Series, 1998. Page 132:

No exception has ever been detected to the rule that any increase in one form of energy is matched by a corresponding decrease. This has led to the statement known as the first law of thermodynamics, or the law of conservation of energy: In any interaction, the total amount of energy does not change. If a stick of dynamite explodes, the chemical energy stored in the dynamite is exactly equal to the energy of the heat, violent motion, sound, and light produced in the explosion and the remaining chemical energy in the gases produced in the explosion.

[9] Book: Six Easy Pieces: Essentials of Physics Explained By Its Most Brilliant Teacher. Addison-Wesley, 1995. This book is comprised of six chapters taken from the book, Lectures on Physics, by Richard Feynman. Addison-Wesley, 1963.

Page 69: “There is a fact, or if you wish, a law, governing all natural phenomena that are known to date. There is no known exception to this law—it is exact as far as we know. The law is called the conservation of energy.”

[10] Book: Warmth Disperses and Time Passes: The History of Heat. By Hans Christian von Baeyer. Modern Library, 1999. Pages 127-128:

The law of conservation of energy, reborn as the law of conservation of mass/energy, has established itself as one of the few unshakable theoretical guideposts in the wilderness of the world of our sense experiences. In scope and generality it surpasses Newton’s laws of motion, Maxwell’s equations for electricity and magnetism, and even Einstein’s potent little E = mc2. It survived not only the storms of the quantum revolution … but also the flood of cosmological discoveries that shattered ancient preconceptions about the permanence and simplicity of the universe. … It comes as close to an absolute truth as our uncertain age will permit.

[11] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

By the time energy is delivered to us in a usable form, it has typically undergone several conversions. Every time energy changes forms, some portion is “lost.” It doesn’t disappear, of course. In nature, energy is always conserved. That is, there is exactly as much of it around after something happens as there was before. But with each change, some amount of the original energy turns into forms we don’t want or can’t use, typically as so-called waste heat that is so diffuse it can’t be captured.

[12] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Page 10: “The second law of thermodynamics on the other hand introduces the concept of quality of energy. It suggests that any conversion involves generation of low grade energy that cannot be used for useful work and this cannot be eliminated altogether. This imposes physical restriction on the use of energy.”

[13] Article: “The Second Law of Thermodynamics.” New Encyclopaedia Britannica: Macropædia—Knowledge in Depth, 2002. Volume 28.

Page 623: “The second law applies to every type of process—physical, natural, biological, and industrial or technological—and examples of its validity can be seen in life every day.”

[14] Book: Elements of Classical Thermodynamics for Advanced Students of Physics. By A. B. Pippard. Cambridge University Press, 1981.

Page 30: “Moreover, the consequences of the [second] law are so unfailingly verified by experiment that it has come to be regarded as among the most firmly established of all the laws of nature.”

[15] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 2: “Energy is so normal to us, we hardly notice it. When we take a hot shower in the morning, we use energy. To wash we need soap and a towel, which were made in factories that use energy. The bricks, concrete and windows of your room were made using energy. Our clothes and shoes were also made using energy.”

Page 3: “Energy is important to us because we use it to do the things we need, which we call energy services. Among the energy services are cooling and refrigeration, space heating, food-processing, water-cleaning, using mobile phones, driving a car or motorbike, making light and sound, the manufacture of products, and many more.”

Page 22:

Some industries use more energy than others. There are six industrial sectors that are the biggest consumers:

• Power plants, oil refinery and coal transformation processes require large amounts of energy to transform energy in the form that is needed.

• Iron and Steel: the reduction of iron ores into metal is energy intensive, as well as the production of steel.

• Chemicals: basic chemicals used elsewhere in industry, plastics and synthetic fibres, and final products like drugs, cosmetics, fertilizers, et.

• Paper and allied products: for the manufacturing of pulps from woods or other cellulose fibres, and for the manufacturing of paper and final products (i.e. napkins, etc.).

• Non ferrous metal industries: for the melting and refining of metallic materials (copper, steel, aluminum) from ore or scrap. It includes also the manufacturing of the final metal products, such as sheets, bars, rods, plates, etc.

• Non metallic materials, such as cement, glass, and all forms of bricks require a lot of energy in special ovens.

[16] Calculated with data from:

a) Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 17: “Table 1.7. Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Primary Energy Consumption … Consumption per Capita (Million Btu) … 2014 [=] 309”

b) Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Pages 16-17: “Let’s say you hire a first-class athlete to make this much energy for you, for example on bicycle driving a generator. An athlete can generate 300 watts for several hours, so it will take him about three hours of hard work!”

Page 21: “An average person can generate about 50 watt continuously, which is 1.57·109 joules in a year (working all day and night, all days of the week, all weeks of the year).”

c) “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

“1 Btu is approximately equal to 1,055 joules.”

CALCULATION: 309,000,000 Btu/year × 1,055 joules/BTU / 1,570,000,000 joules/person/year = 207.6 people

[17] Calculated with data from:

a) Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 21: “An average person can generate about 50 watt continuously, which is 1.57·109 joules in a year (working all day and night, all days of the week, all weeks of the year).”

Page 22: “For each material that is made, a certain amount of energy was required to make it. This is called the embodied energy. … An average house may easily embody up to 900,000 mega joule! Table 8. Energy embodied in common construction materials … Embodied energy in MJ [megajoules] per kg … Clays bricks [=] 2.5”

b) “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

“1 Btu is approximately equal to 1,055 joules.”

c) Webpage: “8 in. x 2-1/4 in. x 4 in. Clay Brick, Model # RED0126MCO.” Home Depot. Accessed August 14, 2013 at <www.homedepot.com>

“Product Weight (lb.) [=] 5”

CALCULATIONS:

a) (5 lbs./brick / 2.2 lbs./kg) × 2,500,000 joules/kg / 1,055 joules/BTU = 5,386 Btu/brick

b) 900,000,000,000 joules/house / 1,055 joules/Btu = 853,080,569 Btu/house

c) (900,000,000,000 joules/house / 1,570,000,000 joules/person/year) = 573.2

[18] Calculated with:

a) Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 17: “Table 1.7. Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Energy Expendituresb … Energy Expenditures as Share of GDPe (Percent) … 2013 [=] 8.3 … b Expenditures include taxes where data are available.”

b) Dataset: “Table 1.1.5. Gross Domestic Product.” U.S. Department of Commerce, Bureau of Economic Analysis. Last revised January 29, 2016. <www.bea.gov>

“[Billions of dollars] Seasonally adjusted at annual rates”

Line 1: “Gross Domestic Product … 2013 [=] 16,663.2”

CALCULATION: $16,663.2 billion GDP × 8.3% = $1,383.1 billion

[19] Webpage: “CPI Inflation Calculator.” United States Department of Labor, Bureau of Labor Statistics. Accessed February 3, 2016. <www.bls.gov>

“$1,383,045 in 2013 has the same buying power as $1,407,149 in 2015”

“The CPI inflation calculator uses the average Consumer Price Index for a given calendar year. This data represents changes in prices of all goods and services purchased for consumption by urban households. This index value has been calculated every year since 1913. For the current year, the latest monthly index value is used.”

[20] Dataset: “Annual Estimates of the Resident Population for the United States, Regions, States, and Puerto Rico: April 1, 2010 to July 1, 2014.” U.S. Census Bureau, Population Division, December 2014. <www.census.gov>

“Resident Population … July 1, 2013 [=] 316,497,531”

CALCULATION: $1,407,149,000,000 energy expenditures / 316,497,531 people = $4,446 energy expenditures/person

[21] Dataset: “Average Number of People per Household, by Race and Hispanic Origin, Marital Status, Age, and Education of Householder: 2013.” U.S. Census Bureau, November 2013. <www.census.gov>

Total households (In Thousands) = 122,459

CALCULATION: $1,407,149,000,000 energy expenditures / 122,459,000 households = $11,491 energy expenditures/household

[22] Report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 17: “Table 1.7. Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators”

[23] Book: Fifty Major Economists. By Steven Pressman. Routledge, 2006. Pages 79-80:

[I]n the 1970s when OPEC raised oil prices, consumers wound up paying more for gasoline and heating oil. With more consumer dollars going to energy-related products, less could be spent on other goods. As a result, producers of these other goods had to cut back production and lay off workers. These layoffs, in turn, would further reduce consumer spending, leading to further production cutbacks and layoffs.

In addition, the energy shock affected the costs of producing goods. Even those goods using little energy in production still require energy when transported from where they are produced to where consumers buy them. Similarly, the parts required for production have to be transported from elsewhere. On the other hand, the layoffs due to reduced spending will push down wages. Consequently, the rising costs of energy should increase the price of some goods (those using little energy and much labor). Consumers will tend to cut back their spending on those goods whose prices rise, and will buy more goods whose prices fall or remain stable.

[24] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Page 1: “Energy being an ingredient for any economic activity, its availability or lack of it affects the society and consequently, there are greater societal concerns and influences affecting the sector.”

Page 4: “The key role of the energy sector in the economic activities of any economy arises because of the mutual interdependence between economic activities and energy. For example, the energy sector uses inputs from various other sectors (industry, transport, households, etc. and is also a key input for most of the sectors.”

Page 429:

[With rising] oil prices …

2. The cost of production of goods and services rises, which puts pressure on profits of the firms. The effect depends on the energy intensity of production: normally developed countries with lower energy intensity are expected to face lower pressure than the developing countries.

3. Higher costs of goods and services put pressure on general price levels, fueling inflation.

4. Higher costs and inflation, and lower profit margins would put pressures on demand, wages and employment, affecting the economic activities.

5. Effects on economic activities influence financial markets, interest rates and exchange rates.

[25] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fpc.state.gov>

Summary: “Higher gasoline prices burden the budgets of households and businesses. Higher gasoline costs can increase indebtedness or reduce spending on other goods and services.”

[26] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 9: “Around two billion people, one-third of the world population, does not have access to modern forms of energy, and therefore lack the comfort, health, mobility and productivity that modern energy makes possible.”

Page 38: “Biomass was one of the first sources of energy known to mankind, and it continues to be a major source of energy in much of the developing world. Something like 80% of the total energy demand in the developing world is covered by biomass energy, mostly in the form of firewood.”

Page 43:

At the lower end of the ladder, people use more of their own energy, for example to gather wood. Fuel gathering at the lower end of the ladder is a major burden for women and children, because of the heavy loads and the long time it takes. For example, in developing countries women and children spend 9 to 12 hours a week on firewood collection. In Nepal, women spend even two and a half hours every day collecting firewood (the men spend forty-five minutes).

Poor people spend a large part of their time collecting the energy they need. This time cannot be spent in producing things that can be sold, working on the land, or learning. This is called the poverty trap: once you are poor, it is very hard to get out of poverty again, because you need to spend all your time in survival activities. This normally leaves very little time to do things that might get you out of poverty, like education, or production of goods to sell on the market.

[27] Fact sheet: “Indoor air pollution and health.” World Health Organization, September 2011. <www.who.int>

Around 3 billion people still cook and heat their homes using solid fuels in open fires and leaky stoves. About 2.7 billion burn biomass (wood, animal dung, crop waste) and a further 0.4 billion use coal. Most are poor, and live in developing countries.

Such cooking and heating produces high levels of indoor air pollution with a range of health-damaging pollutants, including small soot particles that penetrate deep into the lungs. In poorly ventilated dwellings, indoor smoke can be 100 times higher than acceptable levels for small particles. Exposure is particularly high among women and young children, who spend the most time near the domestic hearth. …

Nearly 2 million people a year die prematurely from illness attributable to indoor air pollution due to solid fuel use (2004 data). Among these deaths, 44% are due to pneumonia, 54% from chronic obstructive pulmonary disease (COPD), and 2% from lung cancer.

… The use of polluting fuels also poses a major burden on development.

• Fuel gathering consumes considerable time for women and children, limiting other productive activities and taking children away from school. In less secure environments, women and children are at risk of injury and violence during fuel gathering.

• Non-renewable harvesting of biomass contributes to deforestation and thus climate change. Methane and black carbon (sooty particles) emitted by inefficient stove combustion are powerful climate change pollutants.

• The lack of access to electricity for at least 1.4 billion of households (many of whom then use kerosene lamps for lighting), creates other health risks, e.g. burns and injuries, as well as constraining other opportunities for health and development, e.g. studying or engaging in small crafts and trades, which require adequate light.

[28] Report: “Impacts of Higher Energy Prices on Agriculture and Rural Economies.” By Ronald Sands, Paul Westcott, and others. United States Department of Agriculture, Economic Research Service, August 2011. <www.ers.usda.gov>

Page 1:

Agricultural production is sensitive to changes in energy prices, either through energy consumed directly or through energy-related inputs such as fertilizer. A number of factors can affect energy prices faced by U.S. farmers and ranchers, including developments in the oil and natural gas markets, and energy taxes or subsidies. …

Higher energy-related production costs would generally lower agricultural output, raise prices of agricultural products, and reduce farm income, regardless of the reason for the energy price increase.

[29] Report: “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions.” Congressional Budget Office, April 2009. <www.cbo.gov>

Page 10:

The impact of higher prices for food will probably be greater in other countries than in the United States because the percentage of households’ income that is spent on food in those other nations is larger and the value of commodities makes up a bigger share of the cost of food. (In 2007, the share of spending for goods and services that a household allocated to food purchases for consumption at home was less than 6 percent in the United States but more than 32 percent in India.)38 In contrast to countries that export commodities, countries that import a large percentage of their food will also be adversely affected by rising global prices for commodities. The United Nations’ Food and Agriculture Organization has estimated that, in contrast to steadily declining real (inflation-adjusted) prices for food commodities between 1974 and 2000, real prices for commodities (including corn, soybeans, and sugarcane) increased by 135 percent between January 2000 and April 2008.39

[30] Article: “Rush to Use Crops as Fuel Raises Food Prices and Hunger Fears.” By Elisabeth Rosenthal. New York Times, April 6, 2011. <www.nytimes.com>

“This year, the United Nations Food and Agriculture Organization reported that its index of food prices was the highest in its more than 20 years of existence. Prices rose 15 percent from October to January alone, potentially ‘throwing an additional 44 million people in low- and middle-income countries into poverty,’ the World Bank said.”

[31] Article: “Poor Haitians Resort to Eating Dirt.” By Jonathan M. Katz. Associated Press, January 30, 2008. <news.nationalgeographic.com>

It was lunchtime in one of Haiti’s worst slums, and Charlene Dumas was eating mud. With food prices rising, Haiti’s poorest can’t afford even a daily plate of rice, and some take desperate measures to fill their bellies. …

Food prices around the world have spiked because of higher oil prices, needed for fertilizer, irrigation and transportation. Prices for basic ingredients such as corn and wheat are also up sharply, and the increasing global demand for biofuels is pressuring food markets as well.

The problem is particularly dire in the Caribbean, where island nations depend on imports and food prices are up 40 percent in places. …

Still, at about 5 cents apiece, the [mud] cookies are a bargain compared to food staples. About 80 percent of people in Haiti live on less than $2 a day and a tiny elite controls the economy.

[32] Report: “Energy Tax Policy: Historical Perspectives on and Current Status of Energy Tax Expenditures.” By Molly F. Sherlock. Congressional Research Service, May 2, 2011. <www.leahy.senate.gov>

Page 11: “The economic well-being and economic security of the nation depends on having stable energy sources. There are national economic costs associated with unstable energy supplies, such as increasing unemployment and inflation that may follow oil price spikes.”

[33] Report: “Renewable Energy: Federal Agencies Implement Hundreds of Initiatives.” U.S. Government Accountability Office, February 2012. <www.gao.gov>

Page 1: “Americans’ daily lives, as well as the economic productivity of the United States, depend on the availability of energy, particularly from fossil fuels. However, concerns over the nation’s reliance on imported oil, rising energy costs, and fossil fuels’ potential contribution to global climate change have renewed the focus on developing renewable energy resources and technologies to meet future energy needs.”

[34] Textbook: Introduction to Air Pollution Science. By Robert F. Phalen and Robert N. Phalen. Jones & Bartlett, 2013.

Page 168: “The availability of affordable electric power is essential for public health and economic prosperity.”

[35] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 32: “Liquid fuels play a vital role in the U.S. energy system and economy, and access to affordable liquid fuels has contributed to the nation’s economic prosperity.”

Page 38:

These alternative cases may also have significant implications for the broader economy. Liquid fuels provide power and raw materials (feedstocks) for a substantial portion of the U.S. economy, and the macroeconomic impacts of both the High Oil and Gas Resource case and the Low/No Net Imports case suggest that significant economic benefits would accrue if some version of those futures were realized (see discussion of NGL [natural gas liquids] later in “Issues in focus”). This is in spite of the fact that petroleum remains a global market in each of the scenarios, which limits the price impacts for gasoline, diesel, and other petroleum-derived fuels. In the High Oil and Gas Resource case, increasing energy production has immediate benefits for the economy. U.S. industries produce more goods with 12 percent lower energy costs in 2025 and 15 percent lower energy costs in 2040. Consumers see roughly 10 percent lower energy prices in 2025, and 13 percent lower energy prices in 2040, as compared with the Reference case. Cheaper energy allows the economy to expand further, with real GDP attaining levels that are on average about 1 percent above those in the Reference case from 2025 through 2040, including growth in both aggregate consumption and investment.

[36] Textbook: Microeconomics for Today (Sixth edition). By Irvin B. Tucker. South-Western Cengage Learning, 2010.

Page 450: “GDP per capita provides a general index of a country’s standard of living. Countries with low GDP per capita and slow growth in GDP per capita are less able to satisfy basic needs for food, shelter, clothing, education, and health.”

[37] Textbook: Microeconomics for Today (Sixth edition). By Irvin B. Tucker. South-Western Cengage Learning, 2010.

Page 450: “GDP per capita provides a general index of a country’s standard of living. Countries with low GDP per capita and slow growth in GDP per capita are less able to satisfy basic needs for food, shelter, clothing, education, and health.”

[38] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[39] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[40] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[41] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Page 10: “The term primary energy is used to designate an energy source that is extracted from a stock of natural resources captured from a flow of resources and that has not undergone any transformation or conversion other than separation and cleaning (IEA 2004). Examples include coal, crude oil, natural gas, solar power, nuclear power, etc.”

[42] Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Glossary (page 221):

Primary Energy Consumption: Consumption of primary energy. (Energy sources that are produced from other energy sources—e.g., coal coke from coal—are included in primary energy consumption only if their energy content has not already been included as part of the original energy source. Thus, U.S. primary energy consumption does include net imports of coal coke, but not the coal coke produced from domestic coal.) The U.S. Energy Information Administration includes the following in U.S. primary energy consumption: coal consumption; coal coke net imports; petroleum consumption (petroleum products supplied, including natural gas plant liquids and crude oil burned as fuel); dry natural gas—excluding supplemental gaseous fuels—consumption; nuclear electricity net generation (converted to Btu using the nuclear plants heat rate); conventional hydroelectricity net generation (converted to Btu using the fossil-fueled plants heat rate); geothermal electricity net generation (converted to Btu using the fossil-fueled plants heat rate), and geothermal heat pump energy and geothermal direct use energy; solar thermal and photovoltaic electricity net generation (converted to Btu using the fossil-fueled plants heat rate), and solar thermal direct use energy; wind electricity net generation (converted to Btu using the fossil-fueled plants heat rate); wood and wood-derived fuels consumption; biomass waste consumption; fuel ethanol and biodiesel consumption; losses and co-products from the production of fuel ethanol and biodiesel; and electricity net imports (converted to Btu using the electricity heat content of 3,412 Btu per kilowatthour).

[43] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[44] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[45] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[46] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[47] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Residential sector: An energy-consuming sector that consists of living quarters for private households. Common uses of energy associated with this sector include space heating, water heating, air conditioning, lighting, refrigeration, cooking, and running a variety of other appliances. The residential sector excludes institutional living quarters. Note: Various EIA programs differ insectoral coverage.

[48] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Commercial sector: An energy-consuming sector that consists of service-providing facilities and equipment of businesses; Federal, State, and local governments; and other private and public organizations, such as religious, social, or fraternal groups. The commercial sector includes institutional living quarters. It also includes sewage treatment facilities. Common uses of energy associated with this sector include space heating, water heating, air conditioning, lighting, refrigeration, cooking, and running a wide variety of other equipment. Note: This sector includes generators that produce electricity and/or useful thermal output primarily to support the activities of the above-mentioned commercial establishments.

[49] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Transportation Sector: An energy-consuming sector that consists of all vehicles whose primary purpose is transporting people and/or goods from one physical location to another. Included are automobiles; trucks; buses; motorcycles; trains, subways, and other rail vehicles; aircraft; and ships, barges, and other waterborne vehicles. Vehicles whose primary purpose is not transportation (e.g., construction cranes and bulldozers, farming vehicles, and warehouse tractors and forklifts) are classified in the sector of their primary use. Note: Various EIA programs differ in sectoral coverage—for more information see <www.eia.gov>. See End-Use Sectors and Energy-Use Sectors.

[50] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Industrial sector: An energy-consuming sector that consists of all facilities and equipment used for producing, processing, or assembling goods. The industrial sector encompasses the following types of activity manufacturing (NAICS codes 31-33); agriculture, forestry, fishing and hunting (NAICS code 11); mining, including oil and gas extraction (NAICS code 21); and construction (NAICS code 23). Overall energy use in this sector is largely for process heat and cooling and powering machinery, with lesser amounts used for facility heating, air conditioning, and lighting. Fossil fuels are also used as raw material inputs to manufactured products. Note: This sector includes generators that produce electricity and/or useful thermal output primarily to support the above-mentioned industrial activities. Various EIA programs differ in sectoral coverage.

[51] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 12:

Industrial Use of Energy

The manufacture of the products we use every day, and the materials that were used e.g. to build our houses, cost a large amount of energy. Factories burn fuels to produce heat and power. Apart from the usual fuels and electricity, industry uses a large variety of less commonly used fuels, like wood chips, bark, and wood waste material from the production of paper, coal briquettes, coke oven gas, and others. Manufacturing processes require large quantities of steam, which is produced in boilers using the combustion of fuels.

[52] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 29: “Table 2.1. Energy Consumption by Sector (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[53] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Electric power sector: An energy-consuming sector that consists of electricity only and combined heat and power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public--i.e., North American Industry Classification System 22 plants. See also Combined heat and power (CHP) plant and Electricity only plant.

Combined heat and power (CHP) plant: A plant designed to produce both heat and electricity from a single heat source. Note: This term is being used in place of the term “cogenerator” that was used by EIA in the past. CHP better describes the facilities because some of the plants included do not produce heat and power in a sequential fashion and, as a result, do not meet the legal definition of cogeneration specified in the Public Utility Regulatory Policies Act (PURPA).

Electricity only plant: A plant designed to produce electricity only. See also Combined heat and power (CHP) plant.

[54] Webpage: “How much energy is consumed in the world by each sector?” U.S. Energy Information Administration. Accessed August 16, 2013 at <www.eia.gov>

There are four major energy end-use sectors: commercial, industrial, residential, and transportation. The electric power sector also consumes energy. The electricity it produces is consumed by the end-use sectors. There are also losses in electricity generation, transmission, and distribution. The electricity consumed by the four major energy end-use sectors and electricity losses can be apportioned to these respective end-use sectors to calculate their total energy use. Losses are the difference between the amount of energy used to generate electricity and the energy content of the electricity consumed at the point of end use.

[55] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 29: “Table 2.1. Energy Consumption by Sector (Trillion Btu)”

NOTE: An Excel file containing the data and calculations is available upon request.

[56] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 12:

Heating can also be carried out with electricity. Think for example of a water heater and an electrical oven. However, this is normally much more expensive than using fossil fuels, and it is only used for relatively small amounts of heat. …

Electricity is the most flexible form of energy: it can be used for virtually any application. No noises or gasses are produced at the place where electricity is used. You don’t need a tank of fuel to power your computer or stereo, it is there the moment you need it and in the form you want to have it. You could say that everywhere you would like to use energy when you are not moving, electricity will do the job, unless it is not possible, or cheaper to combust oil, gas, or coal on the spot.

But there are some disadvantages too. The central generation of electricity means it has to be distributed over the country in order to bring it to your house. This causes an average loss of energy of 10%, and needs a large and expensive distribution system. Electricity is also quite hard to store in large quantities. You need large, heavy batteries to store a reasonable amount of electrical energy. As you have to take these batteries with you on a vehicle, transportation doesn’t work very well on electricity. Of course, trains solve this problem by having their own power lines, which act like very long extension cords!

[57] Calculated with data from the report: “Electric Power Monthly with Data for January 2016.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2016. <www.eia.gov>

Page 15 (in PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

Page 16 (in PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

NOTE: An Excel file containing the data and calculations is available upon request.

[58] Calculated with data from the report: “Electric Power Monthly with Data for January 2016.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2016. <www.eia.gov>

Page 15 (in PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

Page 16 (in PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

NOTE: An Excel file containing the data and calculations is available upon request.

[59] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>

Page 81:

Economic growth is an important factor in electricity demand growth. …

In general, the projected growth of electricity demand in OECD countries, where electricity markets are well established and electricity consumption patterns are mature, is slower than in the non-OECD countries. …

From 2005 to 2012, world GDP increased by 3.7%/year, while world net electricity generation rose by 3.2%/year. In many parts of the world, policy actions aimed at improving efficiency will help to decouple economic growth rates and electricity demand growth rates more in the future (Figure 5-2). In the IEO2016 Reference case, world GDP grows by 3.3%/year, and world net electricity generation grows by 1.9%/year, from 2012 to 2040. The 69% increase in world electricity generation through 2040 is far below what it would be if economic growth and electricity demand growth maintained the same relationship they had in the recent past.

[60] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 109: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”

NOTE: An Excel file containing the data and calculations is available upon request.

[61] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 109: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”

NOTE: An Excel file containing the data and calculations is available upon request.

[62] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 109: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”

[63] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 5: “The first energy crisis in history started in 1630, when charcoal, made from wood, started running out. Coal from coal mines could not be used for this purpose, as it contained too much water and sulphur, which made it burn at a lower temperature. Large parts of the woods in Sweden and Russia were turned into charcoal, to solve this problem. … By this time, [around 1700] most of Europe and especially England had cut down most of their forests.”

Page 42:

In western countries, there is not much pollution produced in homes. Most of us cook on electricity, gas or some fluid fuel, which is quite clean. However, about half of the households in the world depend on firewood and coal for cooking and heating. It is very hard to burn solid fuels in a clean way, because it is hard to mix them thoroughly with air in simple cooking stoves. In fact, only about 5-18 percent of the energy goes in the pot, the rest is wasted. What is more, incomplete burning of solid fuel produces a wide range of health-damaging pollutants, as shown in table 10.

… Of course, the risk of pollutants is the largest when people are near. The problem is that the dirtiest fuels are used exactly at times when people are present: every day, in the kitchen and in heating stoves.

[64] Fact sheet: “Indoor air pollution and health.” World Health Organization, September 2011. <www.who.int>

Around 3 billion people still cook and heat their homes using solid fuels in open fires and leaky stoves. About 2.7 billion burn biomass (wood, animal dung, crop waste) and a further 0.4 billion use coal. Most are poor, and live in developing countries.

Such cooking and heating produces high levels of indoor air pollution with a range of health-damaging pollutants, including small soot particles that penetrate deep into the lungs. In poorly ventilated dwellings, indoor smoke can be 100 times higher than acceptable levels for small particles. Exposure is particularly high among women and young children, who spend the most time near the domestic hearth. …

Non-renewable harvesting of biomass contributes to deforestation and thus climate change. Methane and black carbon (sooty particles) emitted by inefficient stove combustion are powerful climate change pollutants.

[65] Article: “Greeks Raid Forests in Search of Wood to Heat Homes.” Wall Street Journal, January 11, 2013. <online.wsj.com>

Tens of thousands of trees have disappeared from parks and woodlands this winter across Greece, authorities said, in a worsening problem that has had tragic consequences as the crisis-hit country’s impoverished residents, too broke to pay for electricity or fuel, turn to fireplaces and wood stoves for heat.

As winter temperatures bite, that trend is dealing a serious blow to the environment, as hillsides are denuded of timber and smog from fires clouds the air in Athens and other cities, posing risks to public health.

[66] Article: “Woodland Heists: Rising Energy Costs Drive Up Forest Thievery.” By Renuka Rayasam. Der Spiegel, January 17, 2013. <www.spiegel.de>

With energy costs escalating, more Germans are turning to wood burning stoves for heat. That, though, has also led to a rise in tree theft in the country’s forests.

The Germany’s Renters Association estimates the heating costs will go up 22 percent this winter alone. A side effect is an increasing number of people turning to wood-burning stoves for warmth. Germans bought 400,000 such stoves in 2011, the German magazine FOCUS reported this week. It marks the continuation of a trend: The number of Germans buying heating devices that burn wood and coal has grown steadily since 2005, according to consumer research company GfK Group.

That increase in demand has now also boosted prices for wood, leading many to fuel their fires with theft.

[67] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 7: “Table 1.3. Primary Energy Consumption by Source (Quadrillion Btu)”

Page 151: “Table 10.1. Renewable Energy Production and Consumption by Source (Trillion Btu)”

Note the growth of wood consumption during the energy crisis of the late 1970s:

Wood Consumption for Energy

[68] Report: “Life Cycle Assessment: Principles and Practice.” By Mary Ann Curran. U.S. Environmental Protection Agency, National Risk Management Research Laboratory, Office of Research and Development, May 2006. <nepis.epa.gov>

Page 1:

Life cycle assessment is a “cradle-to-grave” approach for assessing industrial systems. “Cradle-to-grave” begins with the gathering of raw materials from the earth to create the product and ends at the point when all materials are returned to the earth. LCA evaluates all stages of a product’s life from the perspective that they are interdependent, meaning that one operation leads to the next. LCA enables the estimation of the cumulative environmental impacts resulting from all stages in the product life cycle, often including impacts not considered in more traditional analyses (e.g., raw material extraction, material transportation, ultimate product disposal, etc.). By including the impacts throughout the product life cycle, LCA provides a comprehensive view of the environmental aspects of the product or process and a more accurate picture of the true environmental trade-offs in product and process selection.

The term “life cycle” refers to the major activities in the course of the product’s life-span from its manufacture, use, and maintenance, to its final disposal, including the raw material acquisition required to manufacture the product. Exhibit 1-1 illustrates the possible life cycle stages that can be considered in an LCA and the typical inputs/outputs measured.

[69] Report: “Life-Cycle Greenhouse Gas Emissions of Transportation Fuels: Issues and Implications for Unconventional Fuel Sources.” IPIECA, September 14, 2010. <www.ipieca.org>

Page 13:

Life-cycle analysis is not a precise science. Whilst it does have a role in directing technology research, it provides great uncertainty when being used as a regulatory tool. The boundary and accounting choices are critical, changing the outcomes, when comparing across studies. Additionally, the margins of error in a study can actually be greater than the percentage reduction in emissions required under an LCFS [low carbon fuel standard], raising serious questions about their validity.

[70] Paper: “Emissions from Photovoltaic Life Cycles.” By Vasilis M. Fthenakis and others. Environmental Science & Technology, February 6, 2008. Pages 2168–2174. <pubs.acs.org>

Page 2168:

The production of energy by burning fossil fuels releases many pollutants and carbon dioxide to the environment. Indeed, all anthropogenic means of generating energy, including solar electric, create pollutants when their entire life cycle is taken into account. Life-cycle emissions result from using fossil-fuel-based energy to produce the materials for solar cells, modules, and systems, as well as directly from smelting, production, and manufacturing facilities. These emissions differ in different countries, depending on that country’s mixture in the electricity grid, and the various methods of material/fuel processing.

[71] Report: “Emission Factor Documentation for AP-42 Section 1.1: Bituminous And Subbituminous Coal Combustion.” By: Acurex Environmental Corporation Research, Edward Aul & Associates, H. Pechan and Associates. Prepared for the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards Office Of Air And Radiation, April 1993. <www.epa.gov>

Page 2-1: “The amount and type of coal consumed, design of combustion equipment, and application of emission control technology have a direct bearing on emissions from coal-fired combustion equipment.”

[72] Paper: “Emissions from Photovoltaic Life Cycles.” By Vasilis M. Fthenakis and others. Environmental Science & Technology, February 6, 2008. Pages 2168–2174. <pubs.acs.org>

Page 2168: “Life-cycle emissions result from using fossil-fuel-based energy to produce the materials for solar cells, modules, and systems, as well as directly from smelting, production, and manufacturing facilities. These emissions differ in different countries, depending on that country’s mixture in the electricity grid, and the various methods of material/fuel processing.”

[73] Report: “Electric Power Annual 2011.” U.S. Energy Information Administration, Assistant Administrator for Energy Statistics, January 2013. <www.eia.gov>

Page 217: “Table A.1. Sulfur Dioxide Uncontrolled Emission Factors … Fuel … Bituminous Coal … Cyclone Boiler [=] 38.00 lbs. per ton … Fluidized Bed Boiler [=] 3.80 lbs. per ton”

[74] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

Different types of coal have different characteristics including sulfur content, mercury content, and heat energy content. Heat content is used to group coal into four distinct categories, known as ranks: anthracite, bituminous, subbituminous, and lignite (generally in decreasing order of heat content).

There are far more bituminous coal mines in the United States than the other ranks (over 90% of total mines), but subbituminous mines (located predominantly in Wyoming and Montana) produce more coal because their average size is much larger.

[75] Report: “Emission Factor Documentation for AP-42 Section 1.1: Bituminous And Subbituminous Coal Combustion.” By: Acurex Environmental Corporation Research, Edward Aul & Associates, H. Pechan and Associates. Prepared for the U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards Office Of Air And Radiation, April 1993. <www.epa.gov>

Page 2-2:

Coal-fired boilers can be classified by type, fuel, and method of construction. Boiler types are identified by the heat transfer method (watertube, firetube, or cast iron), the arrangement of the heat transfer surfaces (horizontal or vertical, straight or bent tube), and the firing configuration (suspension, stoker, or fluidized bed). Table 2-2 summarizes boiler type usage by sector. Most of the installed capacity of firetube and cast iron units is oil- and gas-fired3; however, a description of these designs for coal is included here for completeness.

A watertube boiler is one in which the hot combustion gases contact the outside of the heat transfer tubes, while the boiler water and steam are contained within the tubes. Coal-fired watertube boilers consist of pulverized coal, cyclone, stoker, fluidized bed, and handfeed units. Pulverized coal and cyclone boilers are types of suspension systems because some or all of the combustion takes place while the fuel is suspended in the furnace volume. In stoker-fired systems and most handfeed units, the fuel is primarily burned on the bottom of the furnace or on a grate. Some fine particles are entrained in upwardly flowing air, however, and are burned in suspension in the upper furnace volume. In a fluidized bed combustor, the coal is introduced to a bed of either sorbent or inert material (usually sand) which is fluidized by an upward flow of air. Most of the combustion occurs within the bed, but some smaller particles burn above the bed in the “freeboard” space. …

In pulverized coal-fired (PC-fired) boilers the fuel is pulverized to the consistency of light powder and pneumatically injected through the burners into the furnace. Combustion in PC-fired units takes place almost entirely while the coal is suspended in the furnace volume. PC-fired boilers are classified as either dry bottom or wet bottom, depending on whether the ash is removed in solid or molten state. In dry bottom furnaces, coals with high fusion temperatures are burned, resulting in dry ash. In wet bottom furnaces, coals with low fusion temperatures are used, resulting in molten ash or slag. Wet bottom furnaces are also referred to as slag tap furnaces.

Page 2-3:

Wall-fired boilers can be either single wall-fired, with burners on only one wall of the furnace firing horizontally, or opposed wall-fired, with burners mounted on two opposing walls. PC-fired suspension boilers usually are characterized by very high combustion efficiencies, and are generally receptive to low-NOx burners and other combustion modification techniques. Tangential or corner-fired boilers have burners mounted in the corners of the furnace. The fuel and air are injected toward the center of the furnace to create a vortex that is essentially the burner. Because of the large flame volumes and relatively slow mixing, tangential boilers tend to be lower NOx emitters for baseline uncontrolled operation. Cyclone furnaces are often categorized as a PC-fired system even though the coal burned in a cyclone is crushed to a maximum size of about 4.75 mm (4 mesh). The coal is fed tangentially, with primary air, into a horizontal cylindrical furnace. Smaller coal particles are burned in suspension while larger particles adhere to the molten layer of slag on the combustion chamber wall. Cyclone boilers are high-temperature, wet bottom-type systems. Because of their high furnace heat release rate, cyclones are high NOx emitters and are generally more difficult to control with combustion modifications.

[76] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

Nuclear power plants do not emit carbon dioxide, sulfur dioxide, or nitrogen oxides. However, fossil fuel emissions are associated with the uranium mining and uranium enrichment process as well as the transport of the uranium fuel to the nuclear plant. …

Hydropower’s air emissions are negligible because no fuels are burned. …

Emissions associated with generating electricity from solar technologies are negligible because no fuels are combusted. …

Emissions associated with generating electricity from geothermal technologies are negligible because no fuels are combusted. …

Emissions associated with generating electricity from wind technology are negligible because no fuels are combusted.

[77] Paper: “Life Cycle Greenhouse Gas Emissions of Nuclear Electricity Generation: Systematic Review and Harmonization.” By Ethan S. Warner and Garvin A. Heath. Journal of Industrial Ecology, April 2012. Pages S73-S92. <onlinelibrary.wiley.com>

Page S73:

Screening 274 references yielded 27 that reported 99 independent estimates of life cycle GHG emissions from light water reactors (LWRs). The published median, interquartile range (IQR), and range for the pool of LWR life cycle GHG emission estimates were 13, 23, and 220 grams of carbon dioxide equivalent per kilowatt-hour (g CO2-eq/kWh), respectively. After harmonizing methods to use consistent gross system boundaries and values for several important system parameters, the same statistics were 12, 17, and 110 g CO2-eq/kWh, respectively. Harmonization (especially of performance characteristics) clarifies the estimation of central tendency and variability.

Page S90:

This study ultimately concludes that given the large number of previously published life cycle GHG [greenhouse] emissions estimates of nuclear power systems, their relatively narrow distribution postharmonization, and assuming deployment under relatively similar conditions examined in literature passing screens, it is unlikely that new process-based LCAs [life cycle assessments] of LWRs [light water reactors] would fall outside the range of, and will probably be similar in central tendency to, existing literature. The collective LCA literature indicates that life cycle GHG emissions from nuclear power are only a fraction of traditional fossil sources (e.g., Whitaker et al. 2012) and comparable to renewable technologies (e.g., Dolan and Heath 2012). Evidence is limited on whether similar conclusions apply consistently to other common technologies (i.e., HWRs [heavy water reactors] and GCRs [gas-cooled reactors]).

However, the conditions and assumptions under which nuclear power is deployed can have a significant impact on the magnitude of life cycle GHG emissions, and several related contextual and consequential issues remain unexamined in much of the existing literature. …

NOTE: This study only examines greenhouse gases and not air pollutants such are SO2 and NOx. However, because the greenhouse gases emitted in the lifecycle of nuclear power are primarily generated by the usage of fossil fuels, greenhouse gases serve as a rough proxy for qualitative (not quantitative) emissions of air pollutants.

[78] Paper: “Emissions from Photovoltaic Life Cycles.” By Vasilis M. Fthenakis and others. Environmental Science & Technology, February 6, 2008. Pages 2168–2174. <pubs.acs.org>

Page 2173:

Using data compiled from the original records of twelve PV manufacturers, we quantified the emissions from the life cycle of four major commercial photovoltaic technologies and showed that they are insignificant in comparison to the emissions that they replace when introduced in average European and U.S. grids. According to our analysis, replacing grid electricity with central PV systems presents significant environmental benefits, which for CdTe PV amounts to 89–98% reductions of GHG emissions, criteria pollutants, heavy metals, and radioactive species. For roof-top dispersed installations, such pollution reductions are expected to be even greater as the loads on the transmission and distribution networks are reduced, and part of the emissions related to the life cycle of these networks are avoided.

[79] Webpage: “Geothermal Energy and the Environment.” U.S. Energy Information Administration. Last reviewed December 7, 2015. <www.eia.gov>

Geothermal power plants do not burn fuel to generate electricity, so the levels of air pollutants they emit are low. Geothermal power plants release less than 1% of the carbon dioxide emissions released by a fossil fuel power plant. Geothermal power plants further limit air pollution through the use of scrubber systems that remove hydrogen sulfide. Hydrogen sulfide is naturally found in the steam and in the hot water used to generate geothermal power.

Geothermal plants emit 97% less acid rain-causing sulfur compounds than are emitted by fossil fuel power plants. After the steam and water from a geothermal reservoir are used, they are injected back into the earth.

[80] Paper: “Life Cycle Greenhouse Gas Emissions of Utility-Scale Wind Power: Systematic Review and Harmonization.” By Stacey L. Dolan and Garvin A. Heath. Journal of Industrial Ecology, April 2012. Pages S136-S154. <onlinelibrary.wiley.com>

Pages S136: “Interest in technologies powered by renewable energy sources such as the wind and sun has grown partly because of the potential to reduce greenhouse gas (GHG) emissions from the power sector. However, due to GHG emissions produced during equipment manufacture, transportation, on-site construction, maintenance, and decommissioning, wind and solar technologies are not GHG emission-free.”

S151-152: “Life cycle GHG [greenhouse] emissions of wind-powered electricity generation published since 1980 range from 1.7 to 81 g CO2-eq/kWh. Although this is already a tight range, upon harmonizing the data to a consistent set of GWPs [global warming potentials], system lifetime, capacity factors, and gross system boundary, the range of life cycle GHG emission estimates was reduced by 47%, to 3.0 to 45 g CO2- eq/kWh. … The parameter found to have the greatest effect on reducing variability is capacity factor.”

NOTE: This study only examines greenhouse gases and not air pollutants such are SO2 and NOx. However, because the greenhouse gases emitted in the lifecycle of wind turbines are primarily generated by the usage of fossil fuels, greenhouse gases serve as a rough proxy for qualitative (not quantitative) emissions of air pollutants.

[81] Webpage: “Geothermal Heat Pumps.” U.S. Energy Information Administration. Last reviewed September 28, 2015. <www.eia.gov>

“According to the U.S. Environmental Protection Agency (EPA), geothermal heat pumps are the most energy efficient, environmentally clean, and cost effective systems used for temperature control. Geothermal heat pumps can be used for all types of buildings, including homes, office buildings, schools, and hospitals.”

[82] Webpage: “Biodiesel and the Environment.” U.S. Energy Information Administration. Last reviewed October 5, 2015. <www.eia.gov>

“Compared to petroleum diesel fuel, which is refined from crude oil, biodiesel produces fewer air pollutants such as particulates, carbon monoxide, sulfur dioxide, hydrocarbons, and air toxics. Biodiesel does slightly increase emissions of nitrogen oxides.”

[83] Webpage: “Ethanol and the Environment.” U.S. Energy Information Administration. Last reviewed December 15, 2015. <www.eia.gov>

“Ethanol and ethanol-gasoline mixtures burn cleaner and have higher octane than pure gasoline, but have higher evaporative emissions from fuel tanks and dispensing equipment. These evaporative emissions contribute to the formation of harmful, ground-level ozone and smog. Gasoline requires extra processing to reduce evaporative emissions before it is blended with ethanol.”

[84] Paper: “Impacts of biofuel cultivation on mortality and crop yields.” By K. Ashworth and others. Nature Climate Change, January 6, 2013. Pages 492-496. <www.nature.com>

Page 492:

Ground-level ozone is a priority air pollutant …. It is produced in the troposphere through photochemical reactions involving oxides of nitrogen (NOx) and volatile organic compounds (VOCs). … Concerns about climate change and energy security are driving an aggressive expansion of bioenergy crop production and many of these plant species emit more isoprene than the traditional crops they are replacing. Here we quantify the increases in isoprene emission rates caused by cultivation of 72 Mha of biofuel crops in Europe. We then estimate the resultant changes in ground-level ozone concentrations and the impacts on human mortality and crop yields that these could cause.

[85] Webpage: “Ground-Level Ozone: Frequently Asked Questions.” U.S. Environmental Protection Agency. Last updated October 1, 2015. <www3.epa.gov>

Ozone is a gas composed of three atoms of oxygen. Ozone occurs both in the Earth’s upper atmosphere and at ground level. Ozone can be good or bad, depending on where it is found.

Good Ozone

Good ozone occurs naturally in the upper atmosphere, 6 to 30 miles above the Earth’s surface, where it forms a protective layer that shields us from the sun’s harmful ultraviolet rays. This beneficial ozone is gradually being destroyed by manmade chemicals. When the protective ozone “layer” has been significantly depleted; for example, over the North or South Pole; it is sometimes called a “hole in the ozone.”

Bad Ozone

Troposheric, or ground level ozone, is not emitted directly into the air, but is created by chemical reactions between oxides of nitrogen (NOx) and volatile organic compounds (VOC). Ozone is likely to reach unhealthy levels on hot sunny days in urban environments. Ozone can also be transported long distances by wind. For this reason, even rural areas can experience high ozone levels.

[86] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

“Biomass power plants emit nitrogen oxide, a small amount of sulfur dioxide, and carbon dioxide. The amounts emitted depend on the type of biomass that is burned and the type of generator used. … Biomass contains much less sulfur and nitrogen than coal;6 therefore, when biomass is co-fired with coal, sulfur dioxide and nitrogen oxides emissions are lower than when coal is burned alone.”

[87] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

Natural gas offers a number of significant environmental benefits over other fossil fuels. Largely a result of its chemical simplicity, it is the cleanest burning of all fossil fuels. Natural gas is primarily composed of methane, with most of the impurities removed by gas processing at the field and gas plant. …

… Studies indicate that vehicles operating on natural gas versus conventional fuels such as gasoline and diesel fuels can reduce CO output by 90% to 97% and CO2 by 25%. The switch can also significantly reduce NOx emissions, as well as nonhydrocarbon emissions and particulates.

[88] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 25: “Natural gas is made up mainly of methane (CH4), a compound that has a carbon atom surrounded by four hydrogen atoms. Methane is highly flammable and burns almost completely. There is no ash and very little air pollution. Natural gas is colourless and in its pure form, odourless.”

[89] Book: Energy and the Missing Resource: A View from the Laboratory. By I. Dostrovsky. Cambridge University Press, 1988.

Pages 21-22: “Natural gas consists essentially of methane diluted by some other light hydrocarbons and contaminated at times by carbon dioxide and hydrogen sulfide. These diluents or noxious gases must be removed before the methane is shipped to consumers. Beyond this relatively simple operation, the raw material requires little processing.”

[90] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

At the power plant, the burning of natural gas produces nitrogen oxides … but in lower quantities than burning coal or oil. … Similarly, methane can be emitted as the result of leaks and losses during transportation. Emissions of sulfur dioxide and mercury compounds from burning natural gas are negligible.

The average emissions rates in the United States from natural gas-fired generation are … 0.1 lbs/MWh [pounds per megawatthour] of sulfur dioxide, and 1.7 lbs/MWh of nitrogen oxides.1 Compared to the average air emissions from coal-fired generation, natural gas produces … less than a third as much nitrogen oxides, and one percent as much sulfur oxides at the power plant. In addition, the process of extraction, treatment, and transport of the natural gas to the power plant generates additional emissions.

[91] Webpage: “Civic Natural Gas: Frequently Asked Questions.” American Honda Motor Company. Accessed February 3, 2016 at <automobiles.honda.com>

“In fact, the Civic Natural Gas is the cleanest internal-combustion vehicle ever tested by the U.S. Environmental Protection Agency (2). … (2) EPA Tier-2, Bin-2 and ILEV certification as of December 2013.”

[92] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

When coal is burned … sulfur dioxide, nitrogen oxides, and mercury compounds are released. For that reason, coal-fired boilers are required to have control devices to reduce the amount of emissions that are released.

The average emission rates in the United States from coal-fired generation are … 13 lbs/MWh [pounds per megawatthour] of sulfur dioxide, and 6 lbs/MWh of nitrogen oxides.3

Mining, cleaning, and transporting coal to the power plant generate additional emissions.

NOTE: The table below was constructed by Just Facts with data from this EPA webpage:

Average U.S. Emissions of Electricity Generation (pounds per megawatthour)

Fuel

SO2

NOx

Natural gas†

0.1

1.7

Coal†

13.0

6.0

Oil†

12.0

4.0

Municipal solid waste‡

0.8

5.4

Cited sources:

† U.S. EPA, eGRID 2000.

‡ U.S. EPA, Compilation of Air Pollutant Emission Factors (AP-42).

[93] Study Guide: “Coal.” U.S. Department of Energy, February, 24, 2010. <energy.gov>

Page 5:

While we may rely on coal for nearly half of our electricity, it is far from being the perfect fuel. Coal contains traces of impurities like sulfur and nitrogen. When coal burns, these impurities are released into the air, where they can combine with water vapor (for example, in clouds) and form droplets that fall to earth as weak forms of sulfuric and nitric acid—called “acid rain.” There are also tiny specks of minerals—including common dirt—mixed in coal. These particles don’t burn and make up the ash left behind in a coal combustor. Some of the particles also get caught up in the swirling combustion gases and, along with water vapor, form the smoke that comes out of a coal plant’s smokestack. Mercury is another potentially harmful emission contained in coal power plant emissions. …

While coal used to be a dirty fuel to burn, technology advances have helped to greatly improve air quality, especially in the last 20 years. Scientists have developed ways to capture the pollutants trapped in coal before they escape into the atmosphere. Today, technology can filter out 99 percent of the tiny particles and remove more than 95 percent of the acid rain pollutants in coal, and also help control mercury.

[94] Presentation: “Changes in Control Technologies at Coal-Fired Units: 2000–2015.” U.S. Environmental Protection Agency, 2015. <www3.epa.gov>

Page 1: “2000 Coal Controls for SO2 and NOX … Virtually all coal-fired units have electrostatic precipitators, baghouses, or other advanced controls for high levels of particulate removal.”

[95] Calculated with the dataset: “Power Plant Emissions Trends.” U.S. Environmental Protection Agency. Last updated March 3, 2016. <www3.epa.gov>

NOTE: An Excel file containing the data and calculations is available upon request.

[96] Proposed Rule: “Regulation To Mitigate the Misfueling of Vehicles and Engines With Gasoline Containing Greater Than Ten Volume Percent Ethanol and Modifications to the Reformulated and Conventional Gasoline Programs.” U.S. Environmental Protection Agency, November 4, 2010. <www.federalregister.gov>

As a result of the Clean Air Act, EPA established standards and measurement procedures for exhaust, evaporative, and refueling emissions of criteria pollutants. From 1975 into the 1980s, motor vehicles became equipped with catalytic converters, first with catalysts capable of oxidizing HC and CO, and then, in response to EPA’s “Tier 0” standards, with three-way catalysts that also reduced NO X. Motor vehicles produced in the 1980s and even more so in the 1990s as a result of more stringent California and Federal (e.g., “Tier 1”) standards evolved to incorporate more sophisticated and durable emission control systems. These systems generally included an onboard computer, oxygen sensor, and electronic fuel injection with more precise closed-loop fuel compensation and therefore A/F ratio control during more of the engine’s operating range. However, even with the use of closed loop systems through the late 1990s, the emission control system and controls remained fairly simple with a limited range of authority and were primarily designed to adjust for component variability (i.e., fuel pressure, injectors, etc.) and not for changes in the fuel composition.

[97] Webpage: “Glossary - Mobile Source Emissions - Past, Present, and Future.” U.S. Environmental Protection Agency, Office of Transportation and Air Quality. Last updated July 09, 2007. <www.epa.gov>

“Catalytic Converter: An anti-pollution device located between a vehicle’s engine and tailpipe. Catalytic converters work by facilitating chemical reactions that convert exhaust pollutants such as carbon monoxide and nitrogen oxides to normal atmospheric gases such as nitrogen, carbon dioxide, and water.”

[98] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

“Catalytic converter: A device containing a catalyst for converting automobile exhaust into mostly harmless products.”

[99] Synthesis Report: “Climate Change 2007.” Based on a draft prepared by Lenny Bernstein and others. World Meteorological Organization/United Nations Environment Programme, Intergovernmental Panel on Climate Change, 2007. <www.ipcc.ch>

Page 36: “Carbon dioxide (CO2) is the most important anthropogenic GHG. Its annual [anthropogenic] emissions have grown between 1970 and 2004 by about 80%, from 21 to 38 gigatonnes (Gt), and represented 77% of total anthropogenic GHG emissions in 2004 (Figure 2.1).”

[100] Book: Dictionary of Environment and Development: People, Places, Ideas and Organizations. By Andy Crump. MIT Press, 1993.

Page 42: “It is known that carbon dioxide contributes more than any other gas to the greenhouse effect….”

[101] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

Nuclear power plants do not emit carbon dioxide, sulfur dioxide, or nitrogen oxides. However, fossil fuel emissions are associated with the uranium mining and uranium enrichment process as well as the transport of the uranium fuel to the nuclear plant. …

Emissions associated with generating electricity from solar technologies are negligible because no fuels are combusted. …

Emissions associated with generating electricity from geothermal technologies are negligible because no fuels are combusted. …

Emissions associated with generating electricity from wind technology are negligible because no fuels are combusted.

[102] Paper: “Life Cycle Greenhouse Gas Emissions of Nuclear Electricity Generation: Systematic Review and Harmonization.” By Ethan S. Warner and Garvin A. Heath. Journal of Industrial Ecology, April 2012. Pages S73-S92. <onlinelibrary.wiley.com>

Page S73:

Screening 274 references yielded 27 that reported 99 independent estimates of life cycle GHG emissions from light water reactors (LWRs). The published median, interquartile range (IQR), and range for the pool of LWR life cycle GHG emission estimates were 13, 23, and 220 grams of carbon dioxide equivalent per kilowatt-hour (g CO2-eq/kWh), respectively. After harmonizing methods to use consistent gross system boundaries and values for several important system parameters, the same statistics were 12, 17, and 110 g CO2-eq/kWh, respectively. Harmonization (especially of performance characteristics) clarifies the estimation of central tendency and variability.

Page S90:

This study ultimately concludes that given the large number of previously published life cycle GHG [greenhouse] emissions estimates of nuclear power systems, their relatively narrow distribution postharmonization, and assuming deployment under relatively similar conditions examined in literature passing screens, it is unlikely that new process-based LCAs [life cycle assessments] of LWRs [light water reactors] would fall outside the range of, and will probably be similar in central tendency to, existing literature. The collective LCA literature indicates that life cycle GHG emissions from nuclear power are only a fraction of traditional fossil sources (e.g., Whitaker et al. 2012) and comparable to renewable technologies (e.g., Dolan and Heath 2012). Evidence is limited on whether similar conclusions apply consistently to other common technologies (i.e., HWRs [heavy water reactors] and GCRs [gas-cooled reactors]).

However, the conditions and assumptions under which nuclear power is deployed can have a significant impact on the magnitude of life cycle GHG emissions, and several related contextual and consequential issues remain unexamined in much of the existing literature. …

[103] Paper: “Emissions from Photovoltaic Life Cycles.” By Vasilis M. Fthenakis and others. Environmental Science & Technology, February 6, 2008. Pages 2168–2174. <pubs.acs.org>

Page 2173:

Using data compiled from the original records of twelve PV manufacturers, we quantified the emissions from the life cycle of four major commercial photovoltaic technologies and showed that they are insignificant in comparison to the emissions that they replace when introduced in average European and U.S. grids. According to our analysis, replacing grid electricity with central PV systems presents significant environmental benefits, which for CdTe PV amounts to 89–98% reductions of GHG emissions, criteria pollutants, heavy metals, and radioactive species. For roof-top dispersed installations, such pollution reductions are expected to be even greater as the loads on the transmission and distribution networks are reduced, and part of the emissions related to the life cycle of these networks are avoided.

[104] Webpage: “Geothermal Energy and the Environment.” U.S. Energy Information Administration. Last reviewed December 7, 2015. <www.eia.gov>

Geothermal power plants do not burn fuel to generate electricity, so the levels of air pollutants they emit are low. Geothermal power plants release less than 1% of the carbon dioxide emissions released by a fossil fuel power plant. Geothermal power plants further limit air pollution through the use of scrubber systems that remove hydrogen sulfide. Hydrogen sulfide is naturally found in the steam and in the hot water used to generate geothermal power.

Geothermal plants emit 97% less acid rain-causing sulfur compounds than are emitted by fossil fuel power plants. After the steam and water from a geothermal reservoir are used, they are injected back into the earth.

[105] Paper: “Life Cycle Greenhouse Gas Emissions of Utility-Scale Wind Power: Systematic Review and Harmonization.” By Stacey L. Dolan and Garvin A. Heath. Journal of Industrial Ecology, April 2012. Pages S136-S154. <onlinelibrary.wiley.com>

Pages S136: “Interest in technologies powered by renewable energy sources such as the wind and sun has grown partly because of the potential to reduce greenhouse gas (GHG) emissions from the power sector. However, due to GHG emissions produced during equipment manufacture, transportation, on-site construction, maintenance, and decommissioning, wind and solar technologies are not GHG emission-free.”

S151-152: “Life cycle GHG [greenhouse] emissions of wind-powered electricity generation published since 1980 range from 1.7 to 81 g CO2-eq/kWh. Although this is already a tight range, upon harmonizing the data to a consistent set of GWPs [global warming potentials], system lifetime, capacity factors, and gross system boundary, the range of life cycle GHG emission estimates was reduced by 47%, to 3.0 to 45 g CO2- eq/kWh. … The parameter found to have the greatest effect on reducing variability is capacity factor.”

[106] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

“Hydropower’s air emissions are negligible because no fuels are burned. However, if a large amount of vegetation is growing along the riverbed when a dam is built, it can decay in the lake that is created, causing the buildup and release of methane, a potent greenhouse gas.”

[107] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

Methane, a primary component of natural gas and a greenhouse gas, can also be emitted into the air when natural gas is not burned completely. Similarly, methane can be emitted as the result of leaks and losses during transportation. …

Mining, cleaning, and transporting coal to the power plant generate additional emissions. For example, methane, a potent greenhouse gas that is trapped in the coal, is often vented during these processes to increase safety….

In addition, oil wells and oil collection equipment are a source of emissions of methane, a potent greenhouse gas. The large engines that are used in the oil drilling, production, and transportation processes burn natural gas or diesel that also produce emissions.

[108] Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

“Global Warming Potential (GWP): An index used to compare the relative radiative forcing of different gases without directly calculating the changes in atmospheric concentrations. GWPs are calculated as the ratio of the radiative forcing that would result from the emission of one kilogram of a greenhouse gas to that from the emission of one kilogram of carbon dioxide over a period of time, such as 100 years.”

[109] Report: “Recent Greenhouse Gas Concentrations.” By T.J. Blasing. U.S. Department of Energy, Carbon Dioxide Information Analysis Center. Last updated February 2014. <cdiac.ornl.gov>

“GWP3(100-yr time horizon) … Carbon dioxide (CO2) [=] 1 … Methane (CH4) [=] 28”

[110] Webpage: “How much carbon dioxide (CO2) is produced when different fuels are burned?” U.S. Energy Information Administration. Last updated June 18, 2015. <www.eia.gov>

Different fuels emit different amounts of carbon dioxide in relation to the energy they produce when burned. To analyze emissions across fuels, compare the amount of CO2 emitted per unit of energy output or heat content.

Pounds of CO2 emitted per million Btu of energy for various fuels:

Coal (anthracite)

228.6

Coal (bituminous)

205.7

Coal (lignite)

215.4

Coal (subbituminous)

214.3

Diesel fuel & heating oil

161.3

Gasoline

157.2

Propane

139

Natural gas

117

The amount of CO2 produced when a fuel is burned is a function of the carbon content of the fuel. The heat content, or the amount of energy produced when a fuel is burned, is mainly determined by the carbon (C) and hydrogen (H) content of the fuel. Heat is produced when C and H combine with oxygen (O) during combustion. Natural gas is primarily methane (CH4), which has a higher energy content relative to other fuels, and thus, it has a relatively lower CO2-to-energy content. Water and various elements, such as sulfur and non-combustible elements in some fuels reduce their heating values and increase their CO2-to-heat contents.

[111] Webpage: “Ethanol and the Environment.” U.S. Energy Information Administration. Last reviewed December 15, 2015. <www.eia.gov>

Ethanol can be considered atmospheric carbon-neutral because the plants used to make fuel ethanol (such as corn and sugarcane, the two major feedstocks for fuel ethanol production) absorb carbon dioxide (CO2) as they grow and may offset the CO2 produced when ethanol is made and burned. In the United States, coal and natural gas are used as heat sources in the fermentation process to make fuel ethanol.

The impact of greater ethanol use on net CO2 emissions depends on how ethanol is made. It also depends on whether or not indirect impacts on land use are included in the calculations. …

[112] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.epa.gov>

“The carbon dioxide emissions from burning biomass may not result in a net increase in carbon emissions if the biomass resources are managed sustainably, but it is not safe to assume biomass power plants are carbon neutral.”

[113] Article: “Ethanol Not Green or Clean, Some Charge.” By Henry C. Jackson. Associated Press, January 30, 2008.

All sides agree that it takes lots of electricity to produce ethanol. Utilities note a typical plant eats up as much energy as 1,600 farms.

The divide comes over where that electricity should come from. Environmental activists believe greener means, such as natural gas, should be used. Power companies argue that coal is the only cost-efficient solution.

In Iowa, the nation’s top producer of corn and ethanol, dozens of plants are producing the fuel and more are being built. That’s prompted a push for two coal-fired electricity plants, in Marshalltown and near Waterloo.

[114] Report: “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions.” Congressional Budget Office, April 2009. <www.cbo.gov>

Page 13: “Producing ethanol from corn and distributing it emits more greenhouse gases than producing gasoline from crude oil and distributing it. (That is, planting, fertilizing, and harvesting corn as an ethanol feedstock uses more fossil-fuel energy than does drilling for petroleum, refining it into gasoline, and delivering it to customers.)”

[115] Paper: “Fuel miles and the blend wall: costs and emissions from ethanol distribution in the United States.” By Bret Strogen and others. Environmental Science & Technology, April 16, 2012. Pages 5285-5293. <www.ncbi.nlm.nih.gov>

Abstract:

As low-level ethanol-gasoline blends have not consistently outperformed ethanol-free gasoline in vehicle performance or tailpipe emissions, national-level economic and environmental goals could be accomplished more efficiently by concentrating consumption of gasoline containing 10% ethanol (i.e., E10) near producers to minimize freight activity. As the domestic transportation of ethanol increased 10-fold in metric ton-kilometers (t-km) from 2000 to 2009, the portion of t-km potentially justified by the E10 blend wall increased from less than 40% to 80%. However, we estimate 10 billion t-km took place annually from 2004 to 2009 for reasons other than the blend wall. This “unnecessary” transportation resulted in more than $240 million in freight costs, 90 million L of diesel consumption, 300,000 metric tons of CO(2)-e emissions, and 440 g of human intake of PM(2.5).

[116] Report: “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions.” Congressional Budget Office, April 2009. <www.cbo.gov>

Pages 12-13:

Research suggests that the use of ethanol currently reduces greenhouse-gas emissions relative to the use of gasoline because, over the “life cycle” of the two fuels— that is, during their production, distribution, and combustion—ethanol uses less fossil fuel energy than does gasoline. Yet if ethanol production continues to increase, whether use of the fuel reduces greenhouse-gas emissions will also depend on changes in land use that might offset the potential reduction in emissions. For example, a substantial amount of carbon already stored in forests or grasslands could be released if those lands were converted into land to grow crops (such as corn) that would be used to make ethanol, or to grow crops that had been displaced by the ethanol feedstocks. …

Analysis of greenhouse-gas emissions from ethanol and gasoline depends on measurements during all stages of their product life cycles, including production, distribution, and combustion of the fuels. In that regard, ethanol has advantages over gasoline during certain stages but disadvantages during others. On balance, the use of corn ethanol that has been produced at plants fueled by natural gas (which accounts for most of the United States’ production of ethanol) is estimated to generate fewer greenhouse-gas emissions than the use of gasoline. …

Looking at the entire life cycle of the two fuels, research conducted at Argonne National Laboratory (ANL) compared the greenhouse-gas emissions of ethanol and gasoline.43 That research, which has been widely accepted by federal agencies, found that the use of corn ethanol as it is currently produced—using coal-fired and natural gas-fired plants—reduces life-cycle greenhouse-gas emissions by about 20 percent when compared with the use of gasoline.44

The reduction in greenhouse-gas emissions depends critically on which fuel is used to produce ethanol. The ANL researchers found that if corn ethanol was produced at a plant that used natural gas to fuel its production processes, the life-cycle greenhouse-gas emissions for ethanol would be about 30 percent lower than those for gasoline. In contrast, corn ethanol that was produced by using energy derived from burning coal would increase lifecycle greenhouse-gas emissions by 3 percent compared with gasoline (because the burning of coal produces a much greater volume of emissions than does the burning of natural gas). Most ethanol plants in the United States are fueled by natural gas. The rest are coal fired or fired jointly by coal and natural gas.

The ANL researchers’ finding that ethanol releases fewer life-cycle greenhouse-gas emissions than gasoline releases has been challenged by some analysts. An alternative viewpoint is that the production of corn ethanol produces more life-cycle greenhouse-gas emissions than gasoline does because the production of such ethanol relies more heavily on fossil fuels than the ANL researchers’ estimates recognize.47 Such analysts also contend that the reductions in greenhouse-gas emissions derived from using by-products of ethanol production to displace the production of other goods—such as animal feeds or fertilizer— are smaller than those assumed in the ANL analysis.48 Those criticisms are not widely embraced, however. Some observers argue that such contentions are based on outdated data, on overestimates of how much fossil fuel is used in farming and in ethanol production, and on underestimates of the extent to which the use of by-products from ethanol production reduces the amount of fossil fuels used for producing other goods.49

43. Michael Wang, May Wu, and Hong Huo, “Life-Cycle Energy and Greenhouse Gas Emission Impacts of Different Corn Ethanol Plant Types,” Environmental Research Letters, vol. 2, no. 2 (2007).

44. ANL’s estimate of the reduction in life-cycle greenhouse-gas emissions from using corn ethanol in place of gasoline is consistent with a range of other recent estimates. For example, a 2006 study found that the use of corn ethanol reduced life-cycle greenhouse gas emissions by 12 percent (see Jason Hill and others, “Environmental, Economic, and Energetic Costs and Benefits of Biodiesel and Ethanol Biofuels,” Proceedings of the National Academy of Sciences, vol. 103, no. 30, July 25, 2006), whereas a 2009 study found a reduction of 50 percent to 60 percent (see Adam J. Liska and others, “Improvements in Life Cycle Energy Efficiency and Greenhouse Gas Emissions of Corn-Ethanol,” Journal of Industrial Ecology, vol. 13, no. 1, 2009).

47. David Pimentel and Tad W. Patzek, “Ethanol Production Using Corn, Switchgrass, and Wood; Biodiesel Production Using Soybean and Sunflower,” Natural Resources Research, vol. 14, no. 1 (March 2005).

48. Coproduct credits—ethanol by-products that reduce the amount of fossil-fuel energy used in other industries—are assumed to reduce the net amount of fossil-fuel energy consumed in producing ethanol. The use of distillers’ dried grains as animal feed, for example, displaces some production of other feeds and reduces the overall use of fossil fuels. The resulting decrease in greenhouse-gas emissions is credited to the production of ethanol.

49. For example, see the discussion in Environmental Protection Agency, Office of Transportation and Air Quality, Regulatory Impact Analysis: Renewable Fuel Standard Program, Report No. EPA420-R-07-004 (April 2007), p. 226.

[117] Webpage: “Ethanol and the Environment.” U.S. Energy Information Administration. Last reviewed December 15, 2015. <www.eia.gov>

“The U.S. government is supporting efforts to produce ethanol with methods that use less energy than conventional fermentation, and that use cellulosic biomass, which requires less cultivation, fertilizer, and pesticides than corn and sugar cane. Cellulosic ethanol feedstock includes native prairie grasses, fast growing trees, sawdust, and even waste paper.”

[118] Public Law 110-140: “Energy Independence and Security Act of 2007.” 110th U.S. Congress. Signed into law by George W. Bush on December 19, 2007. <www.gpo.gov>

Pages 28-29:

(C) BASELINE LIFECYCLE GREENHOUSE GAS EMISSIONS.— The term ‘baseline lifecycle greenhouse gas emissions’ means the average lifecycle greenhouse gas emissions, as determined by the Administrator, after notice and opportunity for comment, for gasoline or diesel (whichever is being replaced by the renewable fuel) sold or distributed as transportation fuel in 2005. …

(E) CELLULOSIC BIOFUEL.—The term ‘cellulosic biofuel’ means renewable fuel derived from any cellulose, hemicellulose, or lignin that is derived from renewable biomass and that has lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 60 percent less than the baseline lifecycle greenhouse gas emissions.

(G) GREENHOUSE GAS.—The term ‘greenhouse gas’ means carbon dioxide, hydrofluorocarbons, methane, nitrous oxide, perfluorocarbons, sulfur hexafluoride. The Administrator may include any other anthropogenically emitted gas that is determined by the Administrator, after notice and comment, to contribute to global warming.

(H) LIFECYCLE GREENHOUSE GAS EMISSIONS.—The term ‘lifecycle greenhouse gas emissions’ means the aggregate quantity of greenhouse gas emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes), as determined by the Administrator, related to the full fuel lifecycle, including all stages of fuel and feedstock production and distribution, from feedstock generation or extraction through the distribution and delivery and use of the finished fuel to the ultimate consumer, where the mass values for all greenhouse gases are adjusted to account for their relative global warming potential.

[119] Webpage: “Ethanol Production and Distribution.” U.S. Department of Energy, Alternative Fuels Data Center. Last updated March 30, 2016. <www.afdc.energy.gov>

Making ethanol from cellulosic feedstocks—such as grass, wood, and crop residues—is more challenging than using starch-based crops. There are two primary pathways to produce cellulosic ethanol: biochemical and thermochemical. The biochemical process involves a pretreatment to release hemicellulose sugars followed by hydrolysis to break cellulose into sugars. Sugars are fermented into ethanol and lignin is recovered and used to produce energy to power the process. The thermochemical conversion process involves adding heat and chemicals to a biomass feedstock to produce syngas, which is a mixture of carbon monoxide and hydrogen. Syngas is mixed with a catalyst and reformed into ethanol and other liquid co-products.

[120] Report: “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions.” Congressional Budget Office, April 2009. <www.cbo.gov>

Summary: “In the future, the use of cellulosic ethanol, which is made from wood, grasses, and agricultural plant wastes rather than corn, might reduce greenhouse-gas emissions more substantially, but current technologies for producing cellulosic ethanol are not commercially viable.”

Page 14:

Cellulosic ethanol—produced by using switchgrass (a North American grass used for hay and forage), corn stover (the leaves and stalks of the corn plant), or forest residues (in general, small or dead wood items not useful for resale and wastes from lumber operations) as feedstocks— offers the potential for greater reductions in greenhouse-gas emissions (see Figure 3). Relative to corn ethanol, cellulosic ethanol is expected to produce fewer net greenhouse-gas emissions because cellulosic wastes (rather than fossil fuels) might be used as a source of energy for an ethanol plant’s operations or in cogeneration facilities (facilities that produce electricity as well as steam that can be used for the plant’s operations). Electricity produced by such facilities could be transmitted to the electric grid, which might reduce the use of fossil fuels in coal-fired or natural gas-fired power plants.50

According to researchers, cellulosic ethanol, if successfully developed, could reduce greenhouse-gas emissions by 85 percent to 95 percent relative to emissions associated with the production of gasoline.51 In the long run, if cellulosic ethanol could be produced on a large scale and if that fuel along with corn ethanol was substituted for gasoline at the levels called for under the EISA mandate, greenhouse-gas emissions might be reduced by about 130 million metric tons of CO2e by 2022, or 6 percent of total projected emissions from the transportation sector and 2 percent of total emissions generated in the United States.52

The technology for large-scale commercial production of the fuel, however, has not yet been developed. Estimates of the reductions in emissions that might be gained from producing and using cellulosic ethanol reflect assumptions about potential future technology and production processes. Considerable technical hurdles must be overcome— to access the sugars within the cellulose and convert them into ethanol—before commercial production of the fuel can occur on a large scale. EIA projects that those technological constraints are substantial enough that the federal mandate for the use of advanced biofuels, including cellulosic ethanol, in 2022—21 billion gallons—will not be met until 2027.53

[121] Article: “A Fine for Not Using a Biofuel That Doesn’t Exist.” By Matthew L. Wald. New York Times, January 9, 2012. <www.nytimes.com>

When the companies that supply motor fuel close the books on 2011, they will pay about $6.8 million in penalties to the Treasury because they failed to mix a special type of biofuel into their gasoline and diesel as required by law.

But there was none to be had. Outside a handful of laboratories and workshops, the ingredient, cellulosic biofuel, does not exist.

In 2012, the oil companies expect to pay even higher penalties for failing to blend in the fuel, which is made from wood chips or the inedible parts of plants like corncobs. Refiners were required to blend 6.6 million gallons into gasoline and diesel in 2011 and face a quota of 8.65 million gallons this year.

[122] Ruling: American Petroleum Institute v. Environmental Protection Agency. United States Court of Appeals for the District of Columbia Circuit, January 25, 2013. <www.cadc.uscourts.gov>

Page 4:

In a January 2012 Final Rule (the “2012 RFS [Renewable Fuel Standard] rule”), EPA projected that 8.65 million gallons of cellulosic biofuel (10.45 million ethanol-equivalent gallons) would be produced in 2012, well short of the 500 million ethanol-equivalent gallons mandated by the Act for that year. … In the same rule, EPA considered but rejected a reduction in the volume of total advanced biofuels required for 2012, stating that other kinds of advanced biofuels could make up for the shortfall.

Page 12: “Apart from their role as captive consumers, the refiners are in no position to ensure, or even contribute to, growth in the cellulosic biofuel industry. ‘Do a good job, cellulosic fuel producers. If you fail, we’ll fine your customers.’

Page 14: “For the reasons set out above, we reject API’s challenge to EPA’s refusal to lower the applicable volume of advanced biofuels for 2012. However, we agree with API that EPA’s 2012 projection of cellulosic biofuel production was in excess of the agency’s statutory authority. We accordingly vacate that aspect of the 2012 RFS rule and remand for further proceedings consistent with this opinion.”

[123] See the section below on biofuels for the latest details about producers’ inability to make enough cellulosic ethanol to meet the mandated amounts specified in federal law.

[124] Paper: “Land Clearing and the Biofuel Carbon Debt.” By Joseph Fargione and others. Science, February 29, 2008. Pages 1235-1238. <www.sciencemag.org>

Page 1237:

Our results show that converting native ecosystems to biofuel production results in large carbon debts. … Converting lowland tropical rainforest in Indonesia and Malaysia to palm biodiesel would result in a biofuel carbon debt … that would take ~86 years to repay…. Until then, producing and using palm biodiesel from this land would cause greater GHG [greenhouse gas] release than would refining and using an energy-equivalent amount of petroleum diesel. Converting tropical peatland rainforest to palm production … would take over 840 years to repay. Soybean biodiesel produced on converted Amazonian rainforest … would require ~320 years to repay as compared with GHG emissions from petroleum diesel. The biofuel carbon debt from biofuels produced on converted Cerrado [Brazilian woodland-savanna] is repaid in the least amount of time of the scenarios that we examined. Sugarcane ethanol produced on … the wetter and more productive end of this woodland-savanna biome, would take ~17 years to repay the biofuel carbon debt. Soybean biodiesel from the drier, less productive grass-dominated end … would take ~37 years. Ethanol from corn produced on newly converted U.S. central grasslands results in a biofuel carbon debt repayment time of ~93 years.

[125] Webpage: “Biodiesel and the Environment.” U.S. Energy Information Administration. Last reviewed October 5, 2015. <www.eia.gov>

Compared to petroleum diesel fuel, which is refined from crude oil, biodiesel produces fewer air pollutants such as particulates, carbon monoxide, sulfur dioxide, hydrocarbons, and air toxics. Biodiesel does slightly increase emissions of nitrogen oxides.

Biodiesel Use May Reduce Greenhouse Gas Emissions

Using a gallon of biodiesel produced in the United States does not produce the CO2 emissions that result from burning about a gallon of petroleum diesel. Biodiesel may be considered carbon-neutral because the plants used to make biodiesel, such as soybeans and palm oil trees, absorb CO2 as they grow. The absorption of CO2 offsets the CO2 produced while making and using biodiesel. Most of the biodiesel produced in the United States is made from soybean oil. Some biodiesel is also produced from used oils or fats, including recycled restaurant grease.

In some parts of the world, large areas of natural vegetation and forests have been cleared and burned to grow soybeans and palm oil trees to make biodiesel. The negative environmental impacts of land clearing may be greater than any potential benefits of using biodiesel produced from soybeans and palm oil trees.

[126] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 3: “To get the energy services we want, we need energy in a useful form in the right place, at the right time.”

Page 27: “In an electrical generator electricity is made by turning a magnet in a magnetic field. The changing magnetic field drives the electrical current. … In the case of hydro power, the falling water is led through a hydro turbine, which drives an electrical generator.”

Page 31:

Nuclear fusion is the process whereby two atoms fuse together, and release lots of energy. Fusion is the energy source of the sun and the stars and is therefore the most common energy source in the universe. The sun burns up the lightest of the elements, hydrogen (600 million tons each second), which fuses to form helium. In the fusion process no pollutants are formed.

In a sense, all energy we use comes from fusion energy. Fossil fuels were once plants that grew using energy from sunlight. Wind is caused by temperature differences in the atmosphere, caused by the sun. Hydro-energy is powered by the evaporation of water, which is caused by the sun as well.

[127] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

The sun’s energy warms the planet’s surface, powering titanic transfers of heat and pressure in weather patterns and ocean currents. … Solar energy also evaporates water that falls as rain and builds up behind dams, where its motion is used to generate electricity via hydropower. …

Finally, it [electricity] reaches an incandescent lightbulb where it heats a thin wire filament until the metal glows….

[128] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

By the time energy is delivered to us in a usable form, it has typically undergone several conversions. Every time energy changes forms, some portion is “lost.” It doesn’t disappear, of course. In nature, energy is always conserved. That is, there is exactly as much of it around after something happens as there was before. But with each change, some amount of the original energy turns into forms we don’t want or can’t use, typically as so-called waste heat that is so diffuse it can’t be captured.

Reducing the amount lost – also known as increasing efficiency – is as important to our energy future as finding new sources because gigantic amounts of energy are lost every minute of every day in conversions.

[129] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Page 10: “The second law of thermodynamics on the other hand introduces the concept of quality of energy. It suggests that any conversion involves generation of low grade energy that cannot be used for useful work and this cannot be eliminated altogether. This imposes physical restriction on the use of energy.”

[130] Article: “The Second Law of Thermodynamics.” New Encyclopaedia Britannica: Macropædia – Knowledge in Depth, 2002. Volume 28.

Page 623: “The second law applies to every type of process—physical, natural, biological, and industrial or technological—and examples of its validity can be seen in life every day.”

[131] Book: Elements of Classical Thermodynamics for Advanced Students of Physics. By A. B. Pippard. Cambridge University Press, 1981.

Page 30: “Moreover, the consequences of the [second] law are so unfailingly verified by experiment that it has come to be regarded as among the most firmly established of all the laws of nature.”

[132] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 17: “Table 1.7. Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators”

NOTE: An Excel file containing the data and calculations is available upon request.

[133] Article: “Newer U.S. homes are 30% larger but consume about as much energy as older homes.” U.S. Energy Information Administration, February 12, 2013. <www.eia.gov>

Analysis from EIA’s most recent Residential Energy Consumption Survey (RECS) shows that U.S. homes built in 2000 and later consume only 2% more energy on average than homes built prior to 2000, despite being on average 30% larger.

Homes built in the 2000s accounted for about 14% of all occupied housing units in 2009. These new homes consumed 21% less energy for space heating on average than older homes (see graph), which is mainly because of increased efficiency in the form of heating equipment and better building shells built to more demanding energy codes. Geography has played a role too. About 53% of newer homes are in the more temperate South, compared with only 35% of older homes.

The increase in energy for air conditioning also reflects this population migration as well as higher use of central air conditioning and increased square footage. Similar to space heating, these gains were likely moderated by increases in efficiency of cooling equipment and improved building shells, but air conditioning was not the only end use that was higher in newer homes. RECS data show that newer homes were more likely than older homes to have dishwashers, clothes washers, clothes dryers, and two or more refrigerators. Newer homes, with their larger square footage, have more computers, TVs, and TV peripherals such as digital video recorders (DVRs) and video game systems. In total, newer homes consumed about 18% more energy on average in 2009 for appliances, electronics, and lighting than older homes.

[134] Article: “Newer U.S. homes are 30% larger but consume about as much energy as older homes.” U.S. Energy Information Administration, February 12, 2013. <www.eia.gov>

RECS [EIA’s most recent Residential Energy Consumption Survey] data show that newer homes were more likely than older homes to have dishwashers, clothes washers, clothes dryers, and two or more refrigerators. Newer homes, with their larger square footage, have more computers, TVs, and TV peripherals such as digital video recorders (DVRs) and video game systems. In total, newer homes consumed about 18% more energy on average in 2009 for appliances, electronics, and lighting than older homes.

[135] Article: “Newer U.S. homes are 30% larger but consume about as much energy as older homes.” U.S. Energy Information Administration, February 12, 2013. <www.eia.gov>

RECS [EIA’s most recent Residential Energy Consumption Survey] data show that newer homes were more likely than older homes to have dishwashers, clothes washers, clothes dryers, and two or more refrigerators. Newer homes, with their larger square footage, have more computers, TVs, and TV peripherals such as digital video recorders (DVRs) and video game systems. In total, newer homes consumed about 18% more energy on average in 2009 for appliances, electronics, and lighting than older homes.

[136] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Page 13: “The efficiency of the appliance affects the demand. The consumer is interested in the useful energy (i.e. the energy required to meet the need and not the final or primary energies).”

[137] Article: “For appliances, choosing the most cost-effective option depends on several factors.” U.S. Energy Information Administration, May 29, 2013. <www.eia.gov>

Consumers in the market for new appliances have a wide range of choices that likely vary by cost, options, and efficiency level. If energy cost effectiveness is a factor in the decision, picking the most cost-effective model involves comparing the upfront purchase price and an estimate of the expected lifetime energy costs of different options. This calculation requires inputs for equipment lifetime, energy costs, appliance performance, and the time value of money.

Upfront capital costs are relatively simple to compare. Customers can quickly review costs, factor in rebates or incentives, and determine the most and least expensive options. But operating costs are also important. For some appliances, cumulative operating costs over time can exceed upfront costs.

For example, the graphic above illustrates the differences in capital and energy costs of four refrigerators of the same size and type with varying efficiency over time. For the first two years, the baseline (least efficient) option has the lowest total cost of ownership. Over time, the more efficient options have lower cumulative operating costs. After two years, the first ENERGY STAR refrigerator (15% more efficient than baseline) becomes more cost effective than the baseline option. After five years, the 25% more efficient refrigerator is the most cost effective. After 19 years, the most efficient option becomes the most cost effective even though it was originally the most expensive. While 19 years may be longer than most people stay in the same house and near the end of a refrigerator’s expected lifetime, EIA survey data show that about 8% of households have a refrigerator that is at least 20 years old.

[138] Webpage: “About ENERGY STAR.” Accessed June 15, 2010 at <www.energystar.gov>

ENERGY STAR is a joint program of the U.S. Environmental Protection Agency and the U.S. Department of Energy helping us all save money and protect the environment through energy efficient products and practices. …

If looking for new household products, look for ones that have earned the ENERGY STAR. They meet strict energy efficiency guidelines set by the EPA and US Department of Energy.

[139] Report: “Covert Testing Shows the Energy Star Program Certification Process Is Vulnerable to Fraud and Abuse.” United States Government Accountability Office, March 2010. <www.gao.gov>

Overview:

GAO’s investigation shows that Energy Star is for the most part a self- certification program vulnerable to fraud and abuse. GAO obtained Energy Star certifications for 15 bogus products, including a gas- powered alarm clock. Two bogus products were rejected by the program and 3 did not receive a response. In addition, two of the bogus Energy Star firms developed by GAO received requests from real companies to purchase products because the bogus firms were listed as Energy Star partners. This clearly shows how heavily American consumers rely on the Energy Star brand. The program is promoted through tax credits and appliance rebates, and federal agencies are required to purchase certain Energy Star certified products. In addition, companies use the Energy Star certification to market their products and consumers buy products relying on the certification by the government of reduced energy consumption and costs. For example, in 2008 Energy Star reported saving consumers $19 billion dollars on utility costs. The table below details several fictitious GAO products certified by Energy Star.

Gas-Powered Alarm Clock

• Product description indicated the clock is the size of a small generator and is powered by gasoline;

• Product was approved by Energy Star without a review of the company Web site or questions of the claimed efficiencies.

Geothermal Heat Pump

• Energy use data reported was more efficient than any product listed as certified on the Energy Star Web site at the time of submission;

• High-energy efficiency data was not questioned by Energy Star; Product is eligible for federal tax credits and state rebate programs.

Computer Monitor

• Product was approved by Energy Star within 30 minutes of submission;

• Private firms contacted GAO’s fictitious firm to purchase products based on participation in the Energy Star program.

Refrigerator

• Self-certified product was submitted, qualified, and listed on the Energy Star Web site within 24 hours

• Product is eligible for federal tax credits and state rebates.

GAO found that for our bogus products, certification controls were ineffective primarily because Energy Star does not verify energy-savings data reported by manufacturers. Energy Star required only 4 of the 20 products GAO submitted for certification to be verified by an independent third party. For 2 of these cases GAO found that controls were effective because the program required an independent verification by a specific firm chosen by Energy Star. However, in another case because Energy Star failed to verify information provided, GAO was able to circumvent this control by certifying that a product met a specific safety standard for ozone emission.

At briefings on GAO’s investigation, DOE and EPA officials agreed that the program is currently based on self-certifications by manufacturers. However, officials stated there are after-market tests and self-policing that ensure standards are maintained. GAO did not test or evaluate controls related to products that were already certified and available to the public. In addition, prior DOE IG, EPA IG, and GAO reports have found that current Energy Star controls do not ensure products meet efficiency guidelines.

Page 10: “We successfully obtained Energy Star qualification for 15 bogus products, including a gas-powered alarm clock and a room cleaner represented by a photograph of a feather duster adhered to a space heater on our manufacturer’s Web site.”

Page 12:

Energy Star Approved Room Cleaner

[140] Home page: “U.S. Green Building Council.” Accessed October 14, 2013 at <www.usgbc.org>

[141] Webpage: “LEED.” U.S. Green Building Council. Accessed October 14, 2013 at <www.usgbc.org>

At its core, LEED is a program that provides third-party verification of green buildings. Building projects satisfy prerequisites and earn points to achieve different levels of certification. Prerequisites and credits differ for each rating system, and teams choose the best fit for the project. Learn more about LEED, the facts, and the LEED rating systems.

What can LEED do for you?

• Lower operating costs and increase asset value

• Conserve energy, water and other resources

• Be healthier and safer for occupants

• Qualify for money-saving incentives, like tax rebates and zoning allowances

[142] Article: “Green schools: Long on promise, short on delivery.” By Thomas Frank. USA Today, December 11. 2012. <www.usatoday.com>

[143] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

[144] Article: “Two perspectives on household electricity use.” U.S. Energy Information Administration, March 6, 2013. <www.eia.gov>

“Electricity and natural gas now account for approximately equal amounts of the energy consumed on site in U.S. households. But because it takes on average nearly three units of energy from primary fuels such as coal, natural gas, and nuclear fuel to generate one unit of electricity, increased electricity use has a disproportionate impact on the amount of total primary energy required to support site-level energy use.”

[145] Article: “Ethanol Blend Wall: Are We There Yet?” U.S. Energy Information Administration, November 23, 2011. <www.eia.gov>

“E85, a fuel blend with 70 percent to 85 percent ethanol content presently used in very limited volumes that may be sold only for use in flex-fuel vehicles that have been specifically designed to accommodate its use.”

NOTE: Observe the range discrepancy with the next footnote.

[146] Webpage: “Flexible Fuel Vehicles.” U.S. Department of Energy, Alternative Fuels Data Center. Last updated October 1, 2013. <www.afdc.energy.gov>

“Flexible fuel vehicles (FFVs) have an internal combustion engine and are capable of operating on gasoline, E85 (a gasoline-ethanol blend containing 51% to 83% ethanol, depending on geography and season), or a mixture of the two.”

[147] Report: “A Primer on Alternative Transportation Fuels.” By Timothy Coffey. National Defense University, Center for Technology and National Security Policy, September 2010. <ctnsp.dodlive.mil>

Page 25: “Table 6. Energy content and chemical composition of several energy sources referenced to gasoline. … Energy per unit volume … Liquid Ethanol [=] .69”

Page 25:

Table 6. Energy content and chemical composition of several energy sources referenced to gasoline. The bracket < > indicates the average chemical formula. (Source: modified from Coffey et al.7)

Energy Per Unit Volume

[148] Report: “Biofuels: Challenges to the Transportation, Sale, and Use of Intermediate Ethanol Blends.” U.S. Government Accountability Office, June 2011. <www.gao.gov>

Page 6: “Because a gallon of ethanol contains only about two-thirds the energy of a gallon of gasoline, the use of E85 results in an approximately 25 percent reduction in fuel economy.”

[149] “Clean Cities Alternative Fuel Price Report.” U.S. Department of Energy, August 1, 2013. <www.afdc.energy.gov>

Page 7: “Ethanol (E85) contains about 30% less energy (BTUs) per volume than gasoline. Flexible fuel vehicles (FFVs) operating on E85 do not experience a loss in operational performance, but may experience a 25-30% decrease in miles driven per gallon compared to operation on gasoline.”

[150] Webpage: “Biodiesel.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Last updated September 27, 2013. <www.fueleconomy.gov>

“Biodiesel can be used in its pure form (B100) or blended with petroleum diesel. Common blends include B2 (2% biodiesel), B5, and B20.”

[151] Calculated with data from:

a) Report: “December 2015 Monthly Energy Review.” U.S. Energy Information Administration, December 23, 2015. <www.eia.gov>

Page 136: “Table 9.4 Retail Motor Gasoline and On-Highway Diesel Fuel Prices

(Dollars per Gallon, Including Taxes… Prices are not adjusted for inflation.”

b) “Clean Cities Alternative Fuel Price Report, January 2015.” U.S. Department of Energy, March 17, 2015.

<www.afdc.energy.gov>

Page 1: “This report’s prices represent retail, at-the-pump sales prices for each fuel, including federal and state motor fuel taxes. In some cases, prices were collected from government or utility refueling facilities and these taxes were not included in the prices reported to Clean Cities. In these instances, although these users are not required to pay these taxes, the appropriate federal and state taxes were added to the reported prices to provide a more representative basis for comparison. In some cases, states may charge a flat annual fee for state motor fuel taxes, especially for gaseous fuels like compressed natural gas (CNG) and liquefied petroleum gas (LPG or propane). These flat fees are not considered in the prices reported in these pages.”

Page 3: “Table 2. January 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

c) “Clean Cities Alternative Fuel Price Report, April 2015.” U.S. Department of Energy, May 28, 2015. <www.afdc.energy.gov>

Page 3: “Table 2. April 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

d) “Clean Cities Alternative Fuel Price Report, July 2015.” U.S. Department of Energy, July 31, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, July 2015”

e) “Clean Cities Alternative Fuel Price Report, October 2015.” U.S. Department of Energy, December 10, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, October 2015”

NOTE: An Excel file containing the data and calculations is available upon request.

[152] Report: “Biofuels Issues and Trends.” U.S. Energy Information Administration, October, 2012. <www.eia.gov>

Page 18:

RINs [Renewable Identification Numbers] for the biomass-based diesel component of RFS2 [Renewable Fuel Standard, Energy Independence and Security Act of 2007] have become especially important to biodiesel producers. The RFS2 compliance mechanism offers an economic incentive to producers of renewable fuel to achieve the mandated levels. Refiners and petroleum product importers demonstrate compliance with the RFS2 through the submission of RINs that are generated by the production of qualifying renewable fuels. Fuel blenders may separate RINs from physical volumes of renewable fuel and subsequently sell any RINs above the quantity needed to meet their individual requirement. Thus, RINs act as tradable credits that can offset any cost disadvantage renewable fuels may have over comparable petroleum products in order to achieve the required levels of consumption.

Biodiesel RIN prices averaged $0.75 per gallon in 2011.42 Because each gallon of biodiesel generates 1.5 RINs due to the ethanol equivalence factor specified in the RFS2, a $0.75-per-gallon RIN value meant that diesel blenders received an average $1.13-per-gallon offset against the price of each gallon of biodiesel blended in excess of the obligated quantity. These RIN values combined with the $1.00-per-gallon tax credit encouraged greater volumes of consumption even though wholesale biodiesel was priced at a large premium to wholesale petroleum diesel.

[153] Article: “Intricacies of Meeting the Renewable Fuels Standard.” Iowa Ag Review (published by the Center for Agricultural and Rural Development at Iowa State University), Spring 2009. By Bruce A. Babcock. <www.card.iastate.edu>

Gasoline producers and importers are assigned a number of RINs that they must give to EPA each year. Because each gallon of biofuels has a RIN associated with it, producers and importers can obtain RINs by buying biofuels and keeping the RINs. Alternatively, they can enter the RIN market and buy the RINs from somebody else. …

The price of a RIN reflects the difference in the market value of a biofuel in meeting fuel demand and the price that is needed to allow biofuel producers to cover the costs of producing the required amount of biofuel. This means that RIN prices will reflect changes in both market values and production costs. Because biofuels substitute for petroleum-based fuels, the price of crude oil will be one factor that determines RIN prices. Higher crude oil prices will lead to lower RIN prices. …

Consumers choose fuel based on retail prices. Blenders use wholesale prices to determine what fuel blends to use. Retail fuel prices equal the wholesale price plus taxes plus transportation costs plus a profit margin. … A reasonable approximation for the spread between wholesale and retail fuel prices is that the retail price equals the wholesale price plus 10 percent plus 40 cents.

[154] Article: “Higher RIN Prices Support Continued Ethanol Blending Despite Lower Gasoline Prices.” U.S. Energy Information Administration, February 23, 2015. <www.eia.gov>

The recent increase in the D6 [ethanol] RIN price, shown as the difference between the green and yellow lines in the graph, appears to be driven at least in part by the decline in gasoline prices. When the economics for ethanol blending may seem to be unfavorable based on spot prices, a higher RIN value reduces the “net of RIN” cost of ethanol blending. …

Over the past few years, ethanol has sold at prices roughly 10% lower [per gallon] than the price of wholesale gasoline, which combined with positive RIN values and the value of octane encourages refiners and blenders to blend ethanol with gasoline. In most cases, ethanol is blended into gasoline up to 10% by volume. This percentage is the maximum blend approved for use in all gasoline-powered vehicles by EPA and is also accepted by all manufacturers as a fuel that does not risk the voiding of vehicle warranties.

As ethanol prices rose to a $0.25/gal-to-$0.30/gal premium over gasoline in December and January, prices for the 2014 D6 ethanol RIN, which can be used for RFS compliance in either 2014 or 2015, increased by roughly the same amount, from about $0.45/gal in November to $0.71/gal in mid-January. This increase in the RIN value reduces the effective price of ethanol and supports ethanol blending despite the unfavorable spot ethanol pricing.

[155] Report: “The Renewable Identification Number System and U.S. Biofuel Mandates.” By Lihong McPhail, Paul Westcott, and Heather Lutman. U.S. Department of Agriculture, Economic Research Service, November 2011. <www.ers.usda.gov>

Page 8:

The actual RIN price includes the core value of RINs, transaction costs, and/ or a speculative component. The core value of a RIN is the gap, if positive, between the supply price … and the demand price … for biofuels at any given quantity…. In aggregate, the total cost of meeting the RFS2 is equal to the mandated quantity times this per-unit cost (RIN price). The RIN price, or the gap between supply price and demand price, represents the per-unit cost of meeting the mandate. …

RIN prices will rise to bridge the gap between the willingness to pay for biofuels and the cost of producing biofuels at the mandated quantity. In theory, the RIN market ensures that mandated demand will generate high enough biofuel prices to allow biofuel producers to cover their production costs up to the RFS2.

Page 10: “When crude oil prices drop, consumers’ willingness to pay for biofuels decreases. The demand curve for biofuels shifts downward, and prices for RINs increase.”

[156] Webpage: “Biodiesel Income Tax Credit.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center. Accessed January 5, 2016 at <www.afdc.energy.gov>

A taxpayer that delivers pure, unblended biodiesel (B100) into the tank of a vehicle or uses B100 as an on-road fuel in their trade or business may be eligible for an incentive in the amount of $1.00 per gallon of biodiesel, agri-biodiesel, or renewable diesel. If the biodiesel was sold at retail, only the person that sold the fuel and placed it into the tank of the vehicle is eligible for the tax credit. The incentive is allowed as a credit against the taxpayer’s income tax liability. … This tax credit is applicable to fuel delivered between January 1, 2005, and December 31, 2016.

[157] Calculated with data from:

a) Report: “Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2013.” U.S. Energy Information Administration, March 2015. <www.eia.gov>

Page xv: “Table ES2. Quantified energy-specific subsidies and support by type, FY 2010 and FY 2013 (million 2013 dollars) … 2013 … Beneficiary … Natural Gas and Petroleum Liquids … Direct Expenditures [=] 62 … Tax Expenditures [=] 2,250 … Research and Development [=] 34 … Federal & RUS [U.S. Department of Agriculture’s Rural Utilities Service] Electricity [=] 0”

b) Report: “December 2015 Monthly Energy Review.” U.S. Energy Information Administration, December 23, 2015. <www.eia.gov>

Page 5: “Table 1.2: Primary Energy Production by Source (Quadrillion BTU) … 2013 … Natural Gas (Dry) [=] 24.859 … Crude Oil [=] 15.781 … NGPL [Natural Gas Plant Liquids] [=] 3.532”

c) Dataset: “Fuel Properties Comparison.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center, February 27, 2013. <www.afdc.energy.gov>

Page 2: “Energy Content (Higher heating value) … Gasoline [=] 124,340 Btu/gal”

NOTES:

- Although the heating values of natural gas and petroleum products differ from one another, given the small ratio of subsidies to energy production shown in the data above, the heating value of a single product (gasoline) provides a sound approximation.

- An Excel file containing the data and calculations is available upon request.

[158] Calculated with data from:

a) Report: “December 2015 Monthly Energy Review.” U.S. Energy Information Administration, December 23, 2015. <www.eia.gov>

Page 136: “Table 9.4 Retail Motor Gasoline and On-Highway Diesel Fuel Prices

(Dollars per Gallon, Including Taxes… Prices are not adjusted for inflation.”

b) “Clean Cities Alternative Fuel Price Report, January 2015.” U.S. Department of Energy, March 17, 2015. <www.afdc.energy.gov>

Page 1: “This report’s prices represent retail, at-the-pump sales prices for each fuel, including federal and state motor fuel taxes. In some cases, prices were collected from government or utility refueling facilities and these taxes were not included in the prices reported to Clean Cities. In these instances, although these users are not required to pay these taxes, the appropriate federal and state taxes were added to the reported prices to provide a more representative basis for comparison. In some cases, states may charge a flat annual fee for state motor fuel taxes, especially for gaseous fuels like compressed natural gas (CNG) and liquefied petroleum gas (LPG or propane). These flat fees are not considered in the prices reported in these pages.”

Page 3: “Table 2. January 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

c) “Clean Cities Alternative Fuel Price Report, April 2015.” U.S. Department of Energy, May 28, 2015. <www.afdc.energy.gov>

Page 3: “Table 2. April 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

d) “Clean Cities Alternative Fuel Price Report, July 2015.” U.S. Department of Energy, July 31, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, July 2015”

e) “Clean Cities Alternative Fuel Price Report, October 2015.” U.S. Department of Energy, December 10, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, October 2015”

f) Email from the Department of Agricultural and Consumer Economics at the University of Illinois at Urbana-Champaign to Just Facts, January 11, 2016.

“2015 national average RINs prices … D6 [ethanol] = 55 cents … D4 [biodiesel] = 74 cents”

g) Article: “Ethanol Blend Wall: Are We There Yet?” U.S. Energy Information Administration, November 23, 2011. <www.eia.gov>

“Ethanol blending in the United States has recently grown to the point where nearly every gallon of gasoline contains 10-percent ethanol by volume (E10), the legal maximum for general use in conventional gasoline-powered vehicles under the gasohol waiver issued in 1979 by the U.S. Environmental Protection Agency (EPA).”

h) “Fuel Properties Comparison.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center, February 27, 2013. <www.afdc.energy.gov>

Page 1: “1 gallon of diesel has 113% of the energy of one gallon of gasoline. … B100 has 103% of the energy in one gallon of gasoline or 93% of the energy of one gallon of diesel. … 1 gallon of propane has 73% of the energy of one gallon of gasoline.”

i) Report: “A Primer on Alternative Transportation Fuels.” By Timothy Coffey. National Defense University, Center for Technology and National Security Policy, September 2010. <ctnsp.dodlive.mil>

Page 25: “Table 6. Energy content and chemical composition of several energy sources referenced to gasoline. … Energy per unit volume … Liquid Ethanol [=] .69”

j) Webpage: “Biodiesel Income Tax Credit.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center. Accessed January 5, 2016 at <www.afdc.energy.gov>

“A taxpayer that delivers pure, unblended biodiesel (B100) into the tank of a vehicle or uses B100 as an on-road fuel in their trade or business may be eligible for an incentive in the amount of $1.00 per gallon of biodiesel, agri-biodiesel, or renewable diesel. If the biodiesel was sold at retail, only the person that sold the fuel and placed it into the tank of the vehicle is eligible for the tax credit. The incentive is allowed as a credit against the taxpayer’s income tax liability. … This tax credit is applicable to fuel delivered between January 1, 2005, and December 31, 2016.”

NOTE: An Excel file containing the data and calculations is available upon request.

[159] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 38:

The electric industry has met this growing demand with increasing efficiency. Between 1929 and 1967, the national average cost of electricity for residential customers plummeted from about 60¢/kWh to 10¢/kWh (in 2005 dollars), and remains around there today. How did the industry achieve such tremendous cost savings and then keep the real price of electricity flat over the past 40 years? Part can be explained by greater efficiency – power plants use less fuel, and new techniques make it cheaper to extract the coal and natural gas that fuels generators. Another part of the answer, though, stems from changes in the way the industry is organized and operated.

[160] Calculated with data from:

a) Report: “Electric Power Annual 2014.” U.S. Energy Information Administration, February 10, 2016. <www.eia.gov>

Page 22 (in PDF): “Table 2.4. Average Price of Electricity to Ultimate Customers”

b) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

Pages 71–74: “Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U.S. city average, all items (1982-84=100, unless otherwise noted)”

NOTE: An Excel file containing the data and calculations is available upon request.

[161] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26:

Electricity peak loads in Kansas are the greatest during the summer months, primarily due to the electricity needs of air-conditioning systems. …

In order to cost-effectively meet the varying demand of their customers at different times of the year and even different times of the day, most utilities maintain a diverse portfolio of electric power plants (e.g., generating units) that use a variety of fuels. These generating units can be distinguished according to the type of power they produce (firm vs. intermittent) as well as the type of load they are designed to meet (base, peak, or intermediate).

[162] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“Electric power systems must match generation and load in real time, with tight tolerances. As a result, both system stress and prices can vary considerably throughout the day. … Load curve shapes vary among regions and change with the season of the year.”

[163] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 1:

“Whole-building electric load” is the total electrical power used by a building at a given moment. The load changes with time in response to changes in lighting levels; heating, ventilating, and air conditioning (HVAC) requirements; and uses such as computers, copy machines, and so on. The curve that represents load as a function of time, called the “load shape,” can often yield useful information. Unexpectedly high night-time loads may indicate waste (such as lights that needlessly remain on when the building is unoccupied); a change in load shape may indicate an equipment or thermostat malfunction; unexpectedly high sensitivity to outdoor temperature may indicate that excessive outdoor air is being brought into the building by the HVAC system; and so on.

[164] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26: “Electricity consumption (also called ‘load’) is divided into three categories: base, peak, and intermediate load. Base load refers to demand that occurs continuously, day and night, seven days a week. Peak load, on the other hand, refers to maximum demand that occurs within a given period of time. Intermediate load is a more generic term applied to demand that occurs between base and peak load.”

[165] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Peak load: The maximum load during a specified period of time.

Base load: The minimum amount of electric power delivered or required over a given period of time at a steady rate.

Base load capacity: The generating equipment normally operated to serve loads on an around-the-clock basis.

Base load plant: A plant, usually housing high-efficiency steam-electric units, which is normally operated to take all or part of the minimum load of a system, and which consequently produces electricity at an essentially constant rate and runs continuously. These units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs.

[166] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 22: “Figure 15: Sketch indicating five parameters that we recommend as a minimum set to characterize load shape. The value of each parameter can be calculated for each day; these values can then be summarized (e.g. average peak load, standard deviation of peak load).”

[167] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Historically, most base-load capacity has been provided using coal or nuclear technologies because, once the plants have been built, low fuel costs make them relatively cheap to operate continuously.”

Page 4: “Pulverized coal power plants, which burn solid coal ignited by injected air, are by far the most common option for generating base-load electricity.”

[168] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 27:

Power plants that are used to meet the minimum or “base load” of the system are referred to as base-load generating units; they are run continuously and operated, in general, so as to produce electricity at a constant rate. Base-load units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs. Costs are minimized by operating units with the lowest fuel costs for the most hours in the year (i.e., at a high capacity factor). Generally, base-load units include nuclear, coal-fired, geothermal, hydropower, and waste-to-energy plants.63

[169] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

Coal remains the dominant fuel for the world’s thermal electric power plants. Coal has been the main thermal electric fuel due to its cheap price, worldwide availability, easy transport, and low-technology threshold. However, as stated above, Coal’s biggest drawback is the pollution emitted from its combustion. …

Typically, base load power stations are large nuclear, hydroelectric, or coal-burning plants that are expensive to build, with high fixed costs. However, they are cheap to maintain and operate. They operate continuously and are difficult to switch on or off.

[170] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 52:

Grid operators dispatch plants – or, call them into service – with the simultaneous goals of providing reliable power at the lowest reasonable cost. Because various generation technologies have differing variable costs, plants are dispatched only when they are part of the most economic combination of plants needed to supply the customers on the grid. For plants operating in RTOs [regional transmission organizations], this cost is determined by the price that generators offer. In other areas, it is determined by the marginal cost of the available generating plants.

[171] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

“The development of IPPs [Independent Power Producers] and the increased efficiency of gas-fired combined cycle plants have allowed gas to become the fuel of choice in both intermediate and peak load phases.”

[172] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 44: “In general, [natural gas] combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.”

[173] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Even though natural gas prices have increased significantly in recent years, natural gas remains the dominant source of peak capacity because power plants using that fuel are less expensive to build than coal-fired plants or nuclear reactors and easier to start up and shut down.”

[174] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“The transition from relatively lower loads to higher loads in the morning is called the ‘morning ramp’. This transition can stress power systems and lead to volatile prices. … Responding to such load changes often requires using units that can start up quickly. These units can be more expensive to operate than units that stay on for long periods such as baseload units. Power prices can increase during ramping, sometimes considerably, for short periods.”

[175] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

“In 2009, coal began losing its price advantage over natural gas for electricity generation in some parts of the country, particularly in the eastern United States as a surge in natural gas production from domestic shale deposits (made possible by advances in drilling technologies) substantially reduced the price of natural gas.”

[176] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36: “The main increased usage of gas has occurred in the U.S. power sector, where the share of electricity produced with natural gas has started to rise because many power plants can switch between gas and the now relatively more expensive (and dirtier) coal.”

[177] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee/Northwest Natural Gas Association Planning Task Force, August 2012. <www.ferc.gov>

Page 3:

In the United States, over the past decade, the single largest sector of natural gas demand growth has occurred in the area of power generation. As emissions from coal-fired power plants have come under increasing public scrutiny, more and more electric utilities and merchant power producers have turned to natural gas for new baseload and peaking generation. This trend has been accelerated in recent years, due to the boom of shale gas production, the relatively short lead time and low cost of natural gas-fired power plant construction, and the robust flexibility that natural gas-fired plants can bring to the area of Variable Energy Resource (VER) integration (i.e., wind and solar).

[178] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 39:

Over the past 20 years, natural gas has been the go-to fuel for new electricity generation capacity. From 1990 to 2011, natural gas-fired plants accounted for 77 percent of all generating capacity additions, and many of the plants added were very efficient combined-cycle plants. However, with slow growth in electricity demand and spikes in natural gas prices between 2005 and 2008, much of the added capacity was used infrequently. Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally. …

At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated. …

In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:

• A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently

• Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas

• Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices

• Rising coal prices.

Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.

Page 41:

Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. … The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements. …

For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity (82). New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely. …

… Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.

[179] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 3:

Although coal is expected to continue its important role in U.S. electricity generation, there are many uncertainties that could affect future outcomes. Chief among them are the relationship between coal and natural gas prices and the potential for policies aimed at reducing greenhouse gas (GHG) emissions. In 2012, natural gas prices were low enough for a few months for power companies to run natural gas-fired generation plants more economically than coal plants in many areas. During those months, coal and natural gas were nearly tied in providing the largest share of total electricity generation, something that had never happened before.

Page 40:

The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC [natural gas combined cycle] units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. … Because fuel prices vary by region, and because there is also considerable variation in efficiencies across the existing fleet of both coal-fired and combined-cycle plants, dispatch-level competition between coal and natural gas continues.

Page 43: “The delivered cost of coal in the [southeastern United States] region is somewhat higher than in many other regions. Central Appalachian and Illinois Basin coals must be transported by rail or barge to the Southeast, and coal from the Powder River Basin must travel great distances by rail. The region also uses some imported coal, typically along the Gulf Coast, which tends to be more expensive.”

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely.

NOTE: Price variations in coal and natural gas are shown in the above graph of fossil fuel costs of electric power plants.

[180] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 27:

In an electrical generator electricity is made by turning a magnet in a magnetic field. The changing magnetic field drives the electrical current. With the exception of solar cells and fuel cells (which are discussed in chapters 4 and 6), all ways of generating electricity in some way drive a generator of this type. For example, fossil fuels are used to heat water into steam, which can be used to power a steam turbine. The steam turbine then drives the electrical generator.

A gas turbine works in a similar way: when the gas is ignited and starts to burn, it expands. The expanding gas is used to power an electrical generator through a turbine. In addition, the heat of the burning gas is then used to make steam, which powers a steam turbine.

This process is called combined cycle, and it has a high efficiency. If the waste heat of the steam turbine is also used, for example by a factory or for household heating, we have a Cogeneration Plant or Combined Heat and Power Plant.

[181] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 40:

The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC [natural gas combined cycle] units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. When the ratio of natural gas prices to coal prices is approximately 1.5 or lower, a typical natural gas-fired combined-cycle plant has lower generating costs than a typical coal-fired plant.

[182] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

A typical coal-fired electrical plant might be 38% efficient, so a little more than one-third of the chemical energy content of the fuel is ultimately converted to usable electricity. …

In natural gas combined cycle, or NGCC, power plants, we now have technology that takes the waste heat from a natural gas turbine and uses it to power a steam turbine, resulting in a power plant that is as much as 60% efficient.5 Similar technologies are being developed for use in coal power plants.

[183] Calculated with data from the report: “April 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, April 26, 2016. <www.eia.gov>

Page 143: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”

NOTE: An Excel file containing the data and calculations is available upon request.

[184] Calculated with data from:

a) Report: “April 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, April 26, 2016. <www.eia.gov>

Page 143: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”

b) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

Pages 71–74: “Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U.S. city average, all items (1982-84=100, unless otherwise noted)”

NOTE: An Excel file containing the data and calculations is available upon request.

[185] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 17: “[N]atural gas gives you a lot of energy for very little money. That is why it is almost always preferable to cook and heat your home with gas, if it is available.”

[186] Article: “Electricity resource planners credit only a fraction of potential wind capacity.” U.S. Energy Information Administration, May 13, 2011. <www.eia.gov>

“Electric power system planners forecast the demand for electricity at the time of the peak, and then identify existing and potential generating resources needed to satisfy that demand, plus enough additional resources to provide a comfortable reserve margin. The goal is to minimize the costs associated with new capacity investments while ensuring reliability for customers.”

[187] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 15: “State utility commissions commonly direct regulated utilities to meet anticipated demand for new capacity using the technology with the lowest levelized cost.”

[188] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 37:

Much of the wholesale market and certain retail markets are competitive, with prices set competitively. Other prices are set based on the service provider’s cost of service. For wholesale markets, FERC either authorizes jurisdictional entities to sell at market-based rates or reviews and authorizes cost-based rates.

In competitive markets, prices reflect the factors driving supply and demand – the physical fundamentals. In markets where rates are set based on costs, these fundamentals matter as well. Supply incorporates generation and transmission, which must be adequate to meet all customers demand simultaneously, instantaneously and reliably.

Page 40: “State regulators approve a utility’s investments in generation and distribution facilities, either in advance of construction or afterwards when the utility seeks to include a facility’s costs in retail rates. Some states eventually developed elaborate integrated resource planning (IRP) processes to determine what facilities should be built.”

[189] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 73: “Regulatory uncertainty also affects capacity planning. New coal plants may require carbon control and sequestration equipment, resulting in higher material, labor, and operating costs. Alternatively, coal plants without carbon controls could incur higher costs for siting and permitting. Because nuclear and renewable power plants (including wind plants) do not emit GHGs [greenhouse gases], their costs are not directly affected by regulatory uncertainty in this area.”

Page 86: “Similarly, actions to reduce GHG emissions can reduce the competiveness of coal, because its high carbon content can translate into a price penalty, in the form of GHG fees, relative to other fuels.”

Page 211: “Although currently there is no Federal legislation in place that restricts GHG emissions, regulators and the investment community have continued to push energy companies to invest in technologies that are less GHG-intensive. The trend is captured in the AEO2013 Reference case through a 3-percentage-point increase in the cost of capital, when evaluating investments in new coal-fired power plants, new coal-to-liquids (CTL) plants without carbon capture and storage (CCS), and pollution control retrofits.”

[190] Report: “Investment Decisions for Baseload Power Plants.” Prepared by ICF International for the National Energy Technology Laboratory, January 29, 2010. <www.netl.doe.gov>

Page x:

Over the last two years, there has been a record level of growth in power plant construction costs. The average cost of building a plant in the U.S. increased over 50 percent from 2006 to 2008. This rapid rise in power plant costs makes investment in baseload plants in particular more risky because they tend to be more capital intensive. The run-up in capital costs was a factor in many utilities’ decision to revise cost estimates and, in some cases, delay or cancel projects.

Page I-1:

Electric utilities continue to need new generation capacity resulting from continuing electric demand growth and the retirement of existing power plants. The decision regarding which technologies to pursue has become extremely complicated, and the direction is unclear. This uncertainty is problematic because the power industry is one of the most capital-intensive industries in the U.S., and accounts for a large portion of the non-governmental, non-financial debt raised in the U.S. Uncertainty complicates this financing process. This is also problematic because of the importance of the power industry to economic performance and environmental impacts.

Page I-6:

Investing in new baseload electric generation capacity involves exchanging an up-front capital outlay in return for an uncertain income stream in the future. Companies will make this exchange if the expected project returns are high enough to cover the initial lump sum as well as compensate them for taking on the project risks. Project risks arise from many sources including policy/regulatory, market, and financial.

These risk factors affect the economic viability of different baseload generation technologies in different ways, and may alter the relative attractiveness of the various investment options from which a generation company may choose. For this reason, the investment decision-making process must incorporate risk into the analysis. For example, technical risks vary considerably between technology types and will be important elements of investment decision making, since, all else being equal, companies would prefer to invest in lower-risk technologies.

Page I-26: “Power plant investment is expensive. Even though utilities have a rate recovery mechanism, full recovery is not guaranteed. Costly and imprudent power plant investments in the 1970s and 1980s have brought about a financial crisis and sometimes bankruptcy for power companies….”

[191] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 1:

This reappraisal of nuclear power is motivated in large part by the expectation that market-based approaches to limit greenhouse-gas emissions could be put in place in the near future. Several options currently being considered by the Congress—including “cap-and-trade” programs— would impose a price on emissions of carbon dioxide, the most common greenhouse gas.1 If implemented, such limits would encourage the use of nuclear technology by increasing the cost of generating electricity with conventional fossil-fuel technologies. The prospect that such legislation will be enacted is probably already reducing investment in conventional coal-fired power plants.

Page 6: “Because power plants can operate for many years (numerous power stations built in the first half of the previous century are still in use), new capacity is expected to replace existing capacity slowly in the absence of a cost advantage.”

[192] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1: “As with any projection, there is uncertainty about all of these factors and their values can vary regionally and across time as technologies evolve and fuel prices change.”

Pages 2-3:

Policy-related factors, such as investment or production tax credits for specified generation sources, can also impact investment decisions. …

… In the AEO2013 [Annual Energy Outlook 2013] reference case a 3-percentage point increase in the cost of capital is added when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). While the 3-percentage point adjustment is somewhat arbitrary, in levelized cost terms its impact is similar to that of an emissions fee of $15 per metric ton of carbon dioxide (CO2) when investing in a new coal plant without CCS, similar to the costs used by utilities and regulators in their resource planning. The adjustment should not be seen as an increase in the actual cost of financing, but rather as representing the implicit hurdle being added to GHG [greenhouse gas]-intensive projects to account for the possibility they may eventually have to purchase allowances or invest in other GHG emission-reducing projects that offset their emissions. As a result, the levelized capital costs of coal-fired plants without CCS [carbon control and sequestration] are higher than would otherwise be expected.

[193] Article: “Ethanol Not Green or Clean, Some Charge.” By Henry C. Jackson. Associated Press, January 30, 2008.

“Robert C. Brown, a professor and the director of the Bioeconomy Institute at Iowa State University … notes that the volatility of natural gas prices are a tough sell for utilities, even though the gas burns more cleanly than a typical coal-fueled plant.”

[194] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 38: “Electric power is one of the most capital intensive industries.”

[195] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee / Northwest Natural Gas Association Planning Task Force, August 2012. <www.ferc.gov>

Page 12: “However, electricity supply and demand must be balanced on a real-time basis in very short intervals (measured in seconds).”

[196] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

The transition from relatively lower loads to higher loads in the morning is called the “morning ramp.” This transition can stress power systems and lead to volatile prices. On this day, the chart shows a distinct morning ramp or increase in load between 5:00 a.m and 7:00 a.m. Responding to such load changes often requires using units that can start up quickly. These units can be more expensive to operate than units that stay on for long periods such as baseload units. Power prices can increase during ramping, sometimes considerably, for short periods.

[197] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 44: “In general, [natural gas] combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.”

[198] Article: “Electric rates not falling along with fuel costs.” By Jonathan Fahey. Associated Press, July 11, 2012. <news.yahoo.com>

“Even though coal accounts for 38 percent of all power produced in the U.S., natural gas plays an outsized role in determining the price of electricity. The price paid for electricity from the last power plant fired up to meet demand at any given moment is what sets the wholesale price for a given region. And since gas-fired power plants are usually the most expensive, they tend to be fired up last.”

[199] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 37: “Sharp changes in demand, as well as extremely high levels of demand, affect prices as well, especially if less-efficient, more-expensive power plants must be turned on to serve load.”

[200] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 2: “Since load must be balanced on a continuous basis, dispatchable technologies generally have more value to a system than non-dispatchable ones, including those whose operation is tied to the availability of an intermittent resource.”

Page 3: “The duty cycle for intermittent renewable resources, wind and solar, is not operator controlled, but dependent on the weather or solar cycle (that is, sunrise/sunset) and so will not necessarily correspond to operator dispatched duty cycles.”

[201] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 54: “[W]ind and solar energy are so-called intermittent sources of energy, meaning that they do not deliver energy all the time. This means that you need back-up power, or a means of storing power for times when there is no sun or wind, which adds to the costs of these energy sources.”

[202] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 1:

Actual plant investment decisions are affected by the specific technological and regional characteristics of a project, which involve numerous other considerations. The projected utilization rate, which depends on the load shape and the existing resource mix in an area where additional capacity may be needed, is one such factor. The existing resource mix in a region can directly affect the economic viability of a new investment through its effect on the economics surrounding the displacement of existing resources. For example, a wind resource that would primarily displace existing natural gas generation will usually have a different value than one that would displace existing coal generation. A related factor is the capacity value, which depends on both the existing capacity mix and load characteristics in a region.

[203] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 1: “Electricity producers, consumers, and policymakers all desire measures that can provide insight into the economic attractiveness of deploying alternate electricity generation technologies. Levelized cost of electricity (LCOE), one commonly cited cost measure, reflects both the capital and operating costs of deploying and running new utility-scale generation capacity of any given type.”

[204] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1: “Levelized cost is often cited as a convenient summary measure of the overall competiveness of different generating technologies. It represents the per-kilowatthour cost (in real dollars) of building and operating a generating plant over an assumed financial life and duty cycle.”

Page 3: “Some technologies, notably solar photovoltaic (PV), are used in both utility-scale plants and distributed end-use residential and commercial applications. As noted above, the levelized cost calculations presented in the tables apply only to utility-scale use of those technologies.”

[205] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 1: “Levelized cost of electricity (LCOE), one commonly cited cost measure, reflects both the capital and operating costs of deploying and running new utility-scale generation capacity of any given type. However, as often noted by EIA1, the direct comparison of LCOE across technologies to determine the economic competitiveness of various generation alternatives is problematic and potentially misleading.”

[206] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1:

As with any projection, there is uncertainty about all of these factors and their values can vary regionally and across time as technologies evolve and fuel prices change. …

It is important to note that, while levelized costs are a convenient summary measure of the overall competiveness of different generating technologies, actual plant investment decisions are affected by the specific technological and regional characteristics of a project, which involve numerous other considerations. The projected utilization rate, which depends on the load shape and the existing resource mix in an area where additional capacity is needed, is one such factor. The existing resource mix in a region can directly affect the economic viability of a new investment through its effect on the economics surrounding the displacement of existing resources.

Page 2: “Since projected utilization rates, the existing resource mix, and capacity values can all vary dramatically across regions where new generation capacity may be needed, the direct comparison of the levelized cost of electricity across technologies is often problematic and can be misleading as a method to assess the economic competitiveness of various generation alternatives.”

[207] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1: “The availability of various incentives, including state or federal tax credits, can also impact the calculation of levelized cost. The values shown in the tables in this discussion do not incorporate any such incentives.”

[208] Email from Just Facts to the U.S. Energy Information Administration on April 11, 2016:

“Could you advise if LCOE [levelized cost of electricity] and LACE [levelized avoided cost of electricity] include the costs of land for each type of technology to be built and operated?”

Email from the U.S. Energy Information Administration to Just Facts on April 11, 2016:

“Yes, the underlying capital and operating costs include typical land acquisition costs for each technology. Generally, land is purchased, and would be included in the capital cost. For some technologies (especially wind), it is more typical to lease the land, making land acquisition an operating cost.”

[209] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 15: “Environmental regulations that affect the electric power sector are represented as they were in place during late 2012, and do not account for any subsequent judicial or regulatory rulings that may have been issued.”

[210] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1: “Costs are estimated using tax depreciation schedules consistent with current law, which vary by technology.”

[211] Email from Just Facts to the U.S. Energy Information Administration on June 12, 2013:

Has anyone produced credible cost estimates for existing capacity (as opposed to cost projections for new capacity in future years)? If so, can you point me to them?

Email from the U.S. Energy Information Administration to Just Facts on June 12, 2013:

Levelized costs are typically applied as a “forward looking” concept. Once something is built, there is (in theory at least) an actual market price for its generation. In practice, these prices are often hard to obtain, since they are often either contained in private contracts or the result of a dynamic market. But in general, levelized cost estimates and actual market prices would likely be poorly correlated anyway, as prices can be set through demand-side considerations (how much the buyer is willing to pay), and are subject to all sorts of project-specific financing terms, incentives, and other contract conditions that are hard to represent in the levelized cost concept. In general, levelized costs are (or have been) used to compare options for future construction, where it is helpful to be able to compare the combination of investment (fixed) and operating (variable) costs among different options. Once a project is built, the decision on how to operate it are based mostly on variable cost considerations, so levelized costs (which include both variable and fixed cost considerations) are of much less interest to system operators and utilities.

[212] Calculated with data from:

a) Report: “2016 Levelized Cost of New Generation Resources from the Annual Energy Outlook 2010.” U.S. Energy Information Administration, January 12, 2010. <www.eia.gov>

b) Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2011.” U.S. Energy Information Administration, April 26, 2011. <www.eia.gov>

c) Dataset: “Consumer Price Index, All Urban Consumers (CPI-U), U.S. City Average, All items.” U.S. Department of Labor, Bureau of Labor Statistics, August 15, 2013. <ftp.bls.gov>

NOTE: An Excel file containing the data and calculations is available upon request.

[213] Calculated with data from:

a) Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.eia.gov>

b) Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015.” U.S. Energy Information Administration, June 3, 2015. <www.eia.gov>

c) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

NOTE: An Excel file containing the data and calculations is available upon request.

[214] Email from Just Facts to the U.S. Energy Information Administration on February 17, 2016:

Did the capital cost of building a geothermal plant actually decrease by 57% in just two years? If so, what would account for the changes? Did the economic life assumption change between 2013 and 2015?

Email from the U.S. Energy Information Administration to Just Facts on February 17, 2016:

The costs shown in the table(s) for geothermal are site-specific, based on the “marginal” (or least-cost) site available to build-out in any given year/region. Costs can vary quite substantially from site to site for geothermal projects, and depend on factors such as depth-to-resource, water temperature, how much of the site has already been developed, distance to transmission, etc. The LCOE tables are based on the costs for a future year, and the particular site evaluated (for geothermal) varies from AEO-to-AEO [Annual Energy Outlook], and even from year-to-year within an AEO edition, as each AEO has a different regional build-out of geothermal resources. The cost changes you see from AEO 2013 to AEO 2015 mostly reflect a change in the particular site being evaluated, and not a change in the underlying technology costs. That is, if we held the site being evaluated constant across AEO’s, you wouldn’t see that much change in cost.

Email from the U.S. Energy Information Administration to Just Facts on February 18, 2016:

Correct, the financial life assumptions are the same for AEO 2013 and AEO 2015 (30 year financial life for all plants).

The capital costs are for a specific site (or rather, specific sites, since they are different from year to year). Essentially, we have a “supply curve” that ranks sites from lowest cost to highest cost, and our economic model figures out how many sites are needed to meet the demand for electricity (among all the competing options). The costs for any given year are then taken from the “next available” plant on the supply curve (that is, the one that would be chosen next if demand increased). It’s a bit more complicated than that, but that’s generally what is going on.

There are a number of factors in the model that affect capital cost as a function of time (or at least as tend to correlate with time). These include things like changes in interest rate (important if you are looking at levelized costs), changes in the cost of key input commodities, the effects of “learning-by-doing”, etc. These factors affect all technologies, including geothermal. However, not all technologies have a similar sort of resource or site-specific supply curve like geothermal. It just works out that between AEO 2013 and 2015, the impacts of the “supply curve” effects (that is, moving to a higher cost marginal site) outweigh the various factors that would have likely brought the technology cost down.

[215] Email from Just Facts to the U.S. Energy Information Administration on February 19, 2016:

“Are LCOE capital costs marginal? If so, to what extent? It sounds like they are technically marginal costs to build a tiny added amount of capacity.”

Email from the U.S. Energy Information Administration to Just Facts on February 19, 2016:

Yes, they are all effectively estimates of what it would cost to build the next unit of capacity (i.e., the next plant) for the specified technology in the given year. For the most part, the slopes of the effective supply curves are shallow enough that the estimates are good over a fairly wide range of builds, but in some cases (especially geothermal … possibly wind or hydro, depending on the year/region/scenario) you may be near an inflection point in the supply curve that narrows the range that the estimate would be good for.

[216] Email from Just Facts to the U.S. Energy Information Administration on August 13, 2013:

Does EIA have a monitoring and feedback mechanism to test previous LCOE [levelized cost of electricity] projections? For example, the 2005 AEO [Annual Energy Outlook] contained LCOEs for 2010. Does EIA have a system to measure how these projections compared to realized costs? I searched through a few of the NEMS Retrospectives and did not find anything of this nature.

Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:

No, although we do have some limited review of previous projections from the AEO to compare with “as-realized” values, we do not have the resources to look at every projected value. Since the LCOE estimates are not really part of the AEO, and because there isn’t really an “actual” as-realized value that we can easily compare to (LCOE is essentially an artificial construct, not an actual, measurable value like megawatts of installed capacity, or total annual generation), we do not include it in our key market benchmarks review.

[217] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 2: “Since load must be balanced on a continuous basis, dispatchable technologies generally have more value to a system than non-dispatchable ones, including those whose operation is tied to the availability of an intermittent resource. The levelized costs for dispatchable and nondispatchable technologies are listed separately in the tables, because caution should be used when comparing them to one another.”

Page 3: “The duty cycle for intermittent renewable resources, wind and solar, is not operator controlled, but dependent on the weather or solar cycle (that is, sunrise/sunset) and so will not necessarily correspond to operator dispatched duty cycles. As a result, their levelized costs are not directly comparable to those for other technologies (even where the average annual capacity factor may be similar) and therefore are shown in separate sections within each of the tables.”

[218] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Pages 26-27:

Electricity differs from other commodities in that it can not be stored on a commercial scale: in other words, electricity stored through currently available mechanical and chemical means encounters very large losses in efficiency. Therefore, in order to provide reliable service, utilities must have enough capacity—defined as instantaneous electrical production—to meet the greatest peak loads experienced.63 This capacity can be provided either from their own generation assets; long-term power purchase agreements; or “real-time” purchases in the spot market.

Generating units that rely on fuel sources whose availability can be controlled by the operators of the plant are said to provide firm power. Power plants that generate electricity from most conventional sources of electricity (e.g., fossil fuels, nuclear, and hydro), as well as some non-conventional sources such as geothermal and landfill wastes, are considered firm power. On the other hand, generating units that rely on fuel sources, such as wind and solar energy, whose availability can not be controlled by the operators of the unit are said to provide intermittent power. Because intermittent resources cannot be depended on to supply electricity at any given moment, units relying on these resources must be accompanied by power plants that provide firm power. For example, dedicated (load-following) units, which operate on standby, can be used to meet demand during periods when the intermittent resource is unavailable, as when the wind is not blowing or the sun is not shining.

63 In practice utilities are required to maintain capacity well in excess of forecasted peak loads. Southwest Power Pool (SPP) requires (with few exceptions) that all members maintain capacity margins 12% greater than forecasted peak load.

[219] Article: “Electricity systems adjust operations to growing wind power output.” U.S. Energy Information Administration, March 25, 2011. Corrected 3/28/11. <www.eia.gov>

[Electric power system] operators must continuously match electricity generation to electricity demand, a process that becomes more difficult with additional intermittency. …

Electric power systems with a large share of intermittent resources may rely more on flexible resources such as gas turbines or hydropower to “firm up” the output of intermittent generators.

[220] Email from the U.S. Energy Information Administration to Just Facts on June 11, 2013:

“We do not generally estimate the physical life of the various electric power technologies that we model. We assume a financial life of 30 years for all technologies.”

[221] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 2: “The levelized cost shown for each utility-scale generation technology in the tables in this discussion are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital (WACC) of 6.6 percent. In reality, the cost recovery period and cost of capital can vary by technology and project type.”

[222] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Pages 45-46:

NRC [the Nuclear Regulatory Commission] has the authority to issue initial operating licenses for commercial nuclear power plants for a period of 40 years. Decisions to apply for operating license renewals are made entirely by nuclear power plant owners, and typically they are based on economics and the ability to meet NRC requirements.

In April 2012, Oyster Creek Unit 1 became the first commercial nuclear reactor to have operated for 40 years, followed by Nine Mile Point Unit 1 in August, R. E. Ginna in September, and Dresden Unit 2 in December 2012. Two additional plants, H.B. Robinson Unit 2 and Point Beach Unit 1, will complete 40 years of operation in 2013. As of December 2012, the NRC had granted license renewals to 72 of the 104 operating U.S. reactors, allowing them to operate for a total of 60 years. Currently, the NRC is reviewing license renewal applications for 13 reactors, and 15 more applications for license renewals are expected between 2013 and 2019.

NRC regulations do not limit the number of license renewals a nuclear power plant may be granted. The nuclear power industry is preparing applications for license renewals that would allow continued operation beyond 60 years. The first such application, for permission to operate a commercial reactor for a total of 80 years is tentatively scheduled to be submitted in 2015. Aging plants may face a variety of issues that could lead to a decision not to apply for a second license renewal, including both economic and regulatory issues—such as increased operation and maintenance (O&M) costs and capital expenditures to meet NRC requirements. Industry research is focused on identifying challenges that aging facilities might encounter and formulating potential approaches to meet those challenges (90, 91). Typical challenges involve degradation of structural materials, maintaining safety margins, and assessing the structural integrity of concrete (92).

The outcome of pending research and market developments will be important to future decisions regarding life extensions beyond 60 years. The AEO2013 Reference case assumes that the operating lives of most of the existing U.S. nuclear power plants will be extended at least through 2040. The only planned retirement included in the Reference case is the announced early retirement of the Oyster Creek nuclear power station in 2019, as reported on Form EIA-860. The Reference case also assumes an additional 7.1 gigawatts of nuclear power capacity retirements by 2040, representing about 7 percent of the current fleet. These generic retirements reflect uncertainty related to issues associated with long-term operations and age management.

Page 219: “The Low Nuclear case assumes that reactors will not receive a second license renewal, so that all existing nuclear plants are retired within 60 years of operation.”

[223] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 6: “Because power plants can operate for many years (numerous power stations built in the first half of the previous century are still in use), new capacity is expected to replace existing capacity slowly in the absence of a cost advantage.”

[224] Article: “Hydropower has a long history in the United States.” U.S. Energy Information Administration, July 8, 2011. <www.eia.gov>

“At the end of 2010, hydro represented 24 of the 25 oldest operating power facilities in the United States and 72% of all electric generating capacity more than 60 years old. Unlike most other generator types, Federal entities (for example, the Bureau of Land Management) built and currently own or operate hydro facilities in many areas of the country.”

[225] Report: “Distributed Generation System Characteristics and Costs in the Buildings Sector.” Prepared by CF International for the U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting, August 2013. <www.eia.gov>

Appendix A: “Photovoltaic (PV) Cost and Performance Characteristics for Residential and Commercial Applications, Final Report,” August 2010.

Appendix A, Page vi:

Lifetime. Crystalline PV modules and balance of plant components (except the inverter) are forecast to have an expected lifetime of 25 years in 2008. Thin-film modules and balance of plant components (except the inverter) are forecast to have a lifetime of 20 years in 2008. Both technologies are forecast to have a lifetime of 30 years by 2035. Inverters, which are assumed to be identical for both crystalline and thin-film technologies, are forecast to have lifetime of 10 years in 2008, rising to 15 years by 2035.

Appendix A, Page 25:

Thin-film technologies are relatively new, and there is little field experience data available to support lifetime projections. However, for forecasting purposes, ICF assumed that thin-film systems would follow similar lifetime trends as more mature crystalline technologies, but lag behind in terms of the time required to achieve these lifetime estimates. For crystalline technologies, ICF developed the forecasting parameters shown in Table 15. This table also shows the forecasting parameters developed for thin-film technologies and inverters. …

Lifetime forecasts are shown in Figure 13. As indicated, the lifetime of thin-film modules is forecast to lag crystalline modules through 2028. From 2028 onward, the lifetime for both technologies is assumed to be 30 years. For forecasting purposes, ICF is estimating that average inverter lifetimes will start at 10 years in 2008, and increase to 15 years by 2018.

[226] Calculated with data from the report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015.” U.S. Energy Information Administration, June 3, 2015. <www.eia.gov>

Pages 2-3:

The LCOE values shown for each utility-scale generation technology in Table 1 and Table 2 in this discussion are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital (WACC) of 6.1%.5 In reality, the cost recovery period and cost of capital can vary by technology and project type. In the AEO2015 reference case, 3 percentage points are added to the cost of capital when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). In LCOE terms, the impact of the cost of capital adder is similar to that of an emissions fee of $15 per metric ton of carbon dioxide (CO2) when investing in a new coal plant without CCS, which is representative of the costs used by utilities and regulators in their resource planning.6/30/2016 6:48 PM The adjustment should not be seen as an increase in the actual cost of financing, but rather as representing the implicit hurdle being added to GHG-intensive projects to account for the possibility that they may eventually have to purchase allowances or invest in other GHG-emission-reducing projects to offset their emissions. As a result, the LCOE values for coal-fired plants without CCS are higher than would otherwise be expected.

[227] Calculated with data from the footnote above and “Loan Calculator and Amortization.” Bankrate. Accessed October 9, 2013 at <www.bankrate.com>

NOTE: An Excel file containing the data and calculations is available upon request.

[228] Email from the U.S. Energy Information Administration to Just Facts on June 12, 2013:

“Once a project is built, the decision on how to operate it are based mostly on variable cost considerations, so levelized costs (which include both variable and fixed cost considerations) are of much less interest to system operators and utilities.”

[229] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 6: “Because power plants can operate for many years (numerous power stations built in the first half of the previous century are still in use), new capacity is expected to replace existing capacity slowly in the absence of a cost advantage.”

[230] Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:

EIA doesn’t produce levelized cost estimates for rooftop solar, in part because the economic decision criteria that a “end-use” customer (that is, a resident or business considering placing PV on their building) are significantly different than the economic decision criteria that a wholesale generator might face. This would include different financing options and costs, different valuations for the energy (wholesale vs. retail electricity displaced), and different abilities to capture tax incentives (especially for residential units).

[231] “2010 Solar Technologies Market Report.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, National Renewable Energy Laboratory, November 2011. <www.nrel.gov>

Page 52:

The LCOEs [levelized costs of electricity] of utility-scale PV systems are generally lower than those of residential and commercial PV systems located in the same region. This is partly due to the fact that installed and O&M [operating and maintenance] costs per watt tend to decrease as PV system size increases, owing to more advantageous economies of scale and other factors (see Section 3.6 on PV installation cost trends and Section 3.7 on PV O&M.) In addition, larger, optimized, better-maintained PV systems can produce electricity more efficiently and consistently.

[232] Report: “Photovoltaic (PV) Pricing Trends: Historical, Recent, and Near-Term Projections.” By David Feldman and others. Lawrence Berkeley National Laboratory, November 2012. <www.nrel.gov>

Page 11:

System size has a significant and beneficial impact on rooftop and ground-mount system prices. Large PV systems not only better amortize fixed project overhead expenses—they also improve installer efficiencies and drive more efficient supply chain strategies. Figure 10 summarizes the modeled price benefits of increased system size across market segments. There are significant economies-of-scale within and across market segments, with diminishing returns as system size increases within each market segment.

[233] Calculated with data from the report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015.” U.S. Energy Information Administration, June 3, 2015. <www.eia.gov>

NOTE: An Excel file containing the data and calculations is available upon request.

[234] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Pages 1-2:

Conceptually, a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost. Avoided cost, which provides a proxy measure for the annual economic value of a candidate project, may be summed over its financial life and converted to a stream of equal annual payments, which may then be divided by average annual output of the project to develop a figure that expresses the “levelized” avoided cost of the project. This levelized avoided cost may then be compared to the levelized cost of the candidate project to provide an indication of whether or not the project’s value exceeds its cost. If multiple technologies are available to meet load, comparisons of each project’s levelized avoided cost to its levelized project cost may be used to determine which project provides the best net economic value. Estimating avoided costs is more complex than for simple levelized costs, because they require tools to simulate the operation of the power system with and without any project under consideration. The economic decisions regarding capacity additions in EIA’s long-term projections reflect these concepts rather than simple comparisons of levelized project costs across technologies.

[235] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 1:

A better assessment of the economic competitiveness of a candidate generation project can be gained through joint consideration of its LCOE [levelized cost of electricity] and its avoided cost, a measure of what it would cost the grid to meet the demand that is otherwise displaced by a new generation project. …

The difference between the LACE [levelized avoided cost of electricity] and LCOE values for the candidate project provides an indication of whether or not its economic value exceeds its cost, where cost is considered net of the value of any production or investment tax credits provided by federal law.

[236] Email from Just Facts to the U.S. Energy Information Administration on June 12, 2013:

The EIA overview of levelized costs states that “a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost.” Have credible estimates of avoided costs for the various generating technologies been performed by anyone? If so, can you point me to them?

Email from the U.S. Energy Information Administration to Just Facts on June 12, 2013:

We are currently working on a paper that will provide an explanation of and estimates for the avoided costs mentioned in the write-up. We plan on hosting a workshop in July to more fully vet these concepts, and I expect that we should be publishing something in conjunction with that workshop. However, in the interim, we don’t have any estimates ready for publication.

[237] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 1: “The difference between the LACE [levelized avoided cost of electricity] and LCOE [levelized cost of electricity] values for the candidate project provides an indication of whether or not its economic value exceeds its cost, where cost is considered net of the value of any production or investment tax credits provided by federal law.”

Page 2:

This paper presents measures of the economic value for three types of power generation projects (onshore wind, solar PV, and advanced combined cycle natural gas generation)2 across 22 regions within the U.S. electricity system based on the difference between the LACE and LCOE values for each project type in each region. These estimates are derived from input and calculations performed within the National Energy Modeling System (NEMS), and reflect the resource utilization and electric grid characteristics that are projected in the Annual Energy Outlook 2013 (AEO 2013) Reference and No Sunset cases. These calculations of economic value do not reflect the direct value of compliance with Renewable Portfolio Standards (RPS), which are currently in force in 30 states. That is, the payment of Renewable Energy Credits or other RPS compliance revenues are not included. …

For projects entering service in 2018, the estimated economic value of onshore wind and solar PV projects is negative and significantly below that of advanced combined cycle (Adv CC) projects in all regions (Table 3a). However, the net economic value of onshore wind and solar PV projects improves significantly over the projection period. By 2035, the economic value of onshore wind is positive in 6 of 20 regions where the technology can be built, and in 3 of 21 regions for solar PV (with 5 additional regions close to breakeven). Improved economics for wind and PV projects over time reflect higher costs to operate existing generation, increased load, and lower LCOE of wind and solar PV due to declining technology costs3. In other regions, wind and solar PV projects continue to be unattractive on a net value basis relative to Adv CC projects.

3 Wind is assumed to not be available in Florida because of the lack of suitable, high-quality wind resources. In New York City, wind cannot be built for lack of significant undeveloped land on which to site a utility-scale wind plant.

Page 3: “Direct comparison of LCOE values significantly understate the advantage of the Adv CC relative to onshore wind in terms of economic value in all regions, while overstating the advantage of Adv CC relative to solar PV (Tables 1a and 3a).”

Page 6: “PV LCOE [levelized cost of electricity] shown in Table 1a includes the 10-percent ITC [investment tax credit] currently embedded as a permanent provision of U.S. tax law. … This differs from the treatment of the permanent 10-percent ITC in other EIA published LCOE estimates, which do not include direct electric power subsidies, and is done to facilitate the comparison of cost, as seen in the market, with value as seen by the market.”

Page 9:

Table 3a looks at the difference between the LACE and LCOE results for the Reference case to provide an indicator of the economic value of each of the 3 project types at the margin for the 2018 and 2035 service entry dates. If LACE is smaller than LCOE, the resource costs more than the combination of resources that would otherwise serve load. Under such conditions, the new resource would generally not be built. However, if the difference between LACE and LCOE is positive, the resource should be attractive as a new build, since its economic value exceeds its cost. As shown in Table 3a, LCOE exceeds LACE for wind projects entering service in 2018 in all regions, indicating the absence of an economic incentive to build additional wind capacity. With modest natural gas prices and a surplus of generating capacity relative to current load, wind would be displacing low-cost incumbent sources like coal and natural gas generation from combined cycle units.

Page 10: “For example, Table 4a shows that there is almost no wind built between 2017 and 2020, consistent with the reported net negative economic value (LACE less LCOE) for this technology in 2018.”

Page 11: “Solar LCOE remains substantially higher than wind LCOE throughout the projection period, but because of its higher LACE values, the economic attractiveness of PV improves along with that of wind.”

[238] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

“These estimates are derived from input and calculations performed within the National Energy Modeling System (NEMS), and reflect the resource utilization and electric grid characteristics that are projected in the Annual Energy Outlook 2013 (AEO 2013) Reference and No Sunset cases.”

[239] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 28:

Construction of wind-generation units slows considerably in the Reference case from recent construction rates, following the assumed expiration of the tax credit for wind power in 2012. The combination of slow growth in electricity demand, little impact from state-level renewable generation requirements, and low prices for competing fuels like natural gas keeps growth relatively low until around 2025, when load growth finally catches up with installed capacity, and natural gas prices increase to a level at which wind is a cost-competitive option in some regions.

[240] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 6: “PV LCOE [levelized cost of electricity] shown in Table 1a includes the 10-percent ITC [investment tax credit] currently embedded as a permanent provision of U.S. tax law. … This differs from the treatment of the permanent 10-percent ITC in other EIA published LCOE estimates, which do not include direct electric power subsidies, and is done to facilitate the comparison of cost, as seen in the market, with value as seen by the market.”

[241] Workshop Discussion Paper: “Assessing the Economic Value of New Utility-Scale Electricity Generation Projects.” U.S. Energy Information Administration, July 2013. <www.eia.gov>

Page 15: “Environmental regulations that affect the electric power sector are represented as they were in place during late 2012, and do not account for any subsequent judicial or regulatory rulings that may have been issued.”

[242] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.compositesworld.com>

Page 1: “Costs are estimated using tax depreciation schedules consistent with current law, which vary by technology.”

[243] Email from Just Facts to the U.S. Energy Information Administration on February 19, 2016:

“Are LCOE capital costs marginal? If so, to what extent? It sounds like they are technically marginal costs to build a tiny added amount of capacity.”

Email from the U.S. Energy Information Administration to Just Facts on February 19, 2016:

Yes, they are all effectively estimates of what it would cost to build the next unit of capacity (i.e., the next plant) for the specified technology in the given year. For the most part, the slopes of the effective supply curves are shallow enough that the estimates are good over a fairly wide range of builds, but in some cases (especially geothermal … possibly wind or hydro, depending on the year/region/scenario) you may be near an inflection point in the supply curve that narrows the range that the estimate would be good for.

[244] Email from Just Facts to the U.S. Energy Information Administration on August 13, 2013:

“Are the LACE values in the discussion paper calculated under the assumption that the financial life of all technologies is 30 years (like LCOE)?”

Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:

“Yes, the LACE calculation utilizes market-value information over a 30-year period.”

[245] Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:

EIA doesn’t produce levelized cost estimates for rooftop solar, in part because the economic decision criteria that a “end-use” customer (that is, a resident or business considering placing PV on their building) are significantly different than the economic decision criteria that a wholesale generator might face. This would include different financing options and costs, different valuations for the energy (wholesale vs. retail electricity displaced), and different abilities to capture tax incentives (especially for residential units).

[246] “2010 Solar Technologies Market Report.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, National Renewable Energy Laboratory, November 2011. <www.nrel.gov>

Page 52:

The LCOEs [levelized costs of electricity] of utility-scale PV systems are generally lower than those of residential and commercial PV systems located in the same region. This is partly due to the fact that installed and O&M [operating and maintenance] costs per watt tend to decrease as PV system size increases, owing to more advantageous economies of scale and other factors (see Section 3.6 on PV installation cost trends and Section 3.7 on PV O&M.) In addition, larger, optimized, better-maintained PV systems can produce electricity more efficiently and consistently.

[247] Report: “Photovoltaic (PV) Pricing Trends: Historical, Recent, and Near-Term Projections.” By David Feldman and others. Lawrence Berkeley National Laboratory, November 2012. <www.nrel.gov>

Page 11:

System size has a significant and beneficial impact on rooftop and ground-mount system prices. Large PV systems not only better amortize fixed project overhead expenses—they also improve installer efficiencies and drive more efficient supply chain strategies. Figure 10 summarizes the modeled price benefits of increased system size across market segments. There are significant economies-of-scale within and across market segments, with diminishing returns as system size increases within each market segment.

[248] Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015.” U.S. Energy Information Administration, June 3, 2015. <www.eia.gov>

Page 4:

When the LACE [levelized avoided cost of electricity] of a particular technology exceeds its LCOE [levelized cost of electricity] at a given time and place, that technology would generally be economically attractive to build. While the build decisions in the real world, and as modeled in the AEO, are somewhat more complex than a simple LACE to LCOE comparison, including such factors as policy and non-economic drivers, the net economic value (LACE minus LCOE, including subsidy, for a given technology, region and year) shown in Table 4 provides a reasonable point of comparison of first-order economic competitiveness among a wider variety of technologies than is possible using either the LCOE or LACE tables individually. In Table 4, a negative difference indicates that the cost of the marginal new unit of capacity exceeds its value to the system, as measured by LACE; a positive difference indicates that the marginal new unit brings in value in excess of its cost by displacing more expensive generation and capacity options.

[249] Calculated with data from the report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015.” U.S. Energy Information Administration, June 3, 2015. <www.eia.gov>

NOTE: An Excel file containing the data and calculations is available upon request.

[250] Report: “Challenges of Electric Power Industry Restructuring for Fuel Suppliers.” U.S. Energy Information Administration, September 1998. <www.eia.gov>

Page 81:

Biomass produced 75 percent of non-hydroelectric renewable electricity in 1997, with wood comprising the largest component of biomass energy. … [W]ood and wood waste … are the principal biomass products used to produce electricity. Their use is greatest in the forest products industry, which consumes about 85 percent of all wood and wood waste used for energy and is the second-largest consumer of electricity in the industrial sector (Figure 23).184 Electric utilities have historically relied on fossil fuels and consumed very little biomass. Of the more than 500 U.S. biomass power production facilities (with total capability near 10 gigawatts), fewer than 20 are owned or operated by electric utilities.

Almost all industrial firms that generate biomass-based electricity do so to achieve multiple objectives. First, most of these firms are producing biomass-related products185 and have waste streams (e.g., pulping liquor) available as (nearly) free fuel. This makes the cost of self-generation cheaper in many cases than purchasing electricity. Despite the fact that the Forest Products Industry self-generates a substantial portion of its electricity demand, its sizeable power requirements leave plenty of room for additional competitively priced self-generation, if such is possible. Second, combusting waste to generate electricity also solves otherwise substantial waste disposal problems. Thus, the net cost of generation is much lower to the forest products industry than it would be if its generating facilities were used only to produce electricity, because a sizable waste disposal cost is being avoided. The use of waste-based fuel by some industrial generators to reduce waste disposal costs while simultaneously providing power is an example of synergy among industrial production, environmental concerns, and energy production.

[251] Calculated with data from the report: “Electric Power Monthly with Data for January 2016.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2016. <www.eia.gov>

Page 15 (in PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

Page 16 (in PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

NOTE: An Excel file containing the data and calculations is available upon request.

[252] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 5: “Biomass technology can generate base-load electricity in certain parts of the country but is typically limited to small applications because fuel costs become prohibitive at large facilities.”

[253] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, July 2012. <www.ferc.gov>

Page 52: “Oil-fired plants: These play a minor role in U.S. power markets. These facilities are expensive to run and also emit more pollutants than gas plants.”

[254] Calculated with data from the report: “April 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, April 26, 2016. <www.eia.gov>

Page 143: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”

NOTE: An Excel file containing the data and calculations is available upon request.

[255] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 3: “The word petroleum, derived from Latin petra and oelum, means literally rock oil and refers to hydrocarbons that occur widely in sedimentary rocks in all the forms of gases, liquids, semisolids, or solids.”

Page 12:

The definition of petroleum has been varied, unsystematic, diverse, and often archaic. …

… This part of the text attempts to alleviate much of the confusion that exists, but it must be remembered that the terminology of petroleum is still open to personal choice and historical usage. …

Petroleum is a mixture of gaseous, liquid, and solid hydrocarbon compounds that occur in sedimentary rock deposits….

Petroleum is a naturally occurring mixture of hydrocarbons, generally in a liquid state (ASTM, 2005b). …

Page 14: “Petroleum and the equivalent term crude oil cover a wide assortment of materials consisting of mixtures of hydrocarbons and other compounds containing variable amounts of sulfur, nitrogen, and oxygen, which may vary in volatility, specific gravity, and viscosity.”

[256] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Petroleum: A broadly defined class of liquid hydrocarbon mixtures. Included are crude oil, lease condensate, unfinished oils, refined products obtained from the processing of crude oil, and natural gas plant liquids.

Crude Oil: A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Depending upon the characteristics of the crude stream, it may also include: 1) small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being recovered from oil well (casinghead) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included; 2) small amounts of nonhydrocarbons produced with the oil, such as sulfur and various metals; and 3) drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale. Liquids produced at natural gas processing plants are excluded.

Hydrocarbon: An organic chemical compound of hydrogen and carbon in the gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (methane, a constituent of natural gas) to the very heavy and very complex.

Lease Condensate: A mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas plant liquids, such as butane and propane, which are recovered at downstream natural gas processing plants or facilities.

Natural Gas Plant Liquids (NGPL): Those hydrocarbons in natural gas that are separated as liquids at natural gas processing plants, fractionating and cycling plants, and, in some instances, field facilities. Lease condensate is excluded. Products obtained include ethane; liquefied petroleum gases (propane, butanes, propane-butane mixtures, ethane-propane mixtures); isopentane; and other small quantities of finished products, such as motor gasoline, special naphthas, jet fuel, kerosene, and distillate fuel oil. See Natural Gas Liquids.

Unfinished Oils: All oils requiring further processing, except those requiring only mechanical blending. Unfinished oils are produced by partial refining of crude oil and include naphthas and lighter oils, kerosene and light gas oils, heavy gas oils, and residuum.

[257] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Petroleum: A broadly defined class of liquid hydrocarbon mixtures. …

Hydrocarbon: An organic chemical compound of hydrogen and carbon in the gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (methane, a constituent of natural gas) to the very heavy and very complex.

Lease Condensate: A mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas plant liquids, such as butane and propane, which are recovered at downstream natural gas processing plants or facilities.

[258] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 3: “The word petroleum … refers to hydrocarbons that occur widely in sedimentary rocks in all the forms of gases, liquids, semisolids, or solids.”

Page 14: “Petroleum … cover a wide assortment of materials consisting of mixtures of hydrocarbons and other compounds containing variable amounts of sulfur, nitrogen, and oxygen, which may vary in volatility, specific gravity, and viscosity.”

[259] Book: Petroleum Chemistry and Refining. Edited by James G. Speight. Taylor and Francis, 1998. Chapter 1: “The Composition of Petroleum.” By Robert B. Long and James G. Speight. Pages 1-38.

Page 8:

[I]t is perhaps remarkable that petroleum has such a narrow spread of elemental (ultimate) composition (Speight, 1991):

Element

Range, weight %

carbon

83.0-87.0

hydrogen

10.0-14.0

nitrogen

0.1-2.0

oxygen

0.05-1.5

sulfur

0.05-6.0

However it is not so much the elemental composition (which may be a reflection of physical or fractional composition) of petroleum that determines its behavior and properties. It is the fractional composition of petroleum, more specifically the differences in petroleum composition of crude oils, that determines the properties and behavior.

In many cases, the differences in properties can be ascribed to differences in the ratios of the various hydrocarbon constituents….

[260] Book: Petroleum Chemistry and Refining. Edited by James G. Speight. Taylor and Francis, 1998. Chapter 1: “The Composition of Petroleum.” By Robert B. Long and James G. Speight. Pages 1-38.

Page 6:

[P]rotopetroleum is a generic term that has been employed on occasion to indicate the product after initial changes in the procuress have occurred that result in the formation of petroleum. In some instances, the terms protopetroleum and kerogen have been used interchangeably, although there is the notion that protopetroleum is the first product of diagenesis and kerogen is the later product of this sequence.

Thus, using this form of terminology, differences in petroleum composition can be ascribed not only to the nature of the precursors that form the protopetroleum but also to the relative amounts of precursors in the mix and the maturation conditions under which the protopetroleum is converted to kerogen and thence to petroleum.

Petroleum is generally accepted as being formed from buried marine sediments by the action of heat and pressure. …

Marine sediment is a term used to describe the organic biomass believed to be the raw material from which petroleum is derived, and it is mixture of many types of marine organic material that collected at the bottom of the seas and then become buried by the geological action of the earth. The types of marine organic material that collected in the sediment could be bacteria, plankton, animals, fish, and marine vegetation in varying proportions in the different sediments buried at various locations around the world. …

These buried marine deposits then undergo a series of concurrent and consecutive chemical reactions collectively called diagenesis under the influence of the temperature, pressure, and long reaction times afforded by history in the earth.

[261] Book: Energy and the Missing Resource: A View from the Laboratory. By I. Dostrovsky. Cambridge University Press, 1988.

Pages 12-13:

[Petroleum is] formed as the breakdown products of plant organisms, mainly of marine origin, that become incorporated in sediments and are then subjected to heat under high pressures over long periods of time. … [T]he precipitated organic matter must escape oxidization by oxygen dissolved in the water. Where stagnant conditions exist, accumulation of sediments rich in organic debris may be formed. Such sediments, when compacted by extensive pressure of accumulated material, become rocks, source rocks as they are called in the petroleum industry, in which oil may be formed.

[262] Article: “Feuding Over the Origins of Fossil Fuels.” By Lisa M. Pinsker. Geotimes (published by the American Geological Institute), October 2005. <www.geotimes.org>

A petroleum geochemist at the U.S. Geological Survey, [Mike] Lewan is an expert on the origins of oil, and quite familiar with an idea that has been lingering within some scientific circles for many years now: that petroleum — oil and natural gas — comes from processes deep in Earth that do not involve organic material. This idea runs contrary to the theory that has driven modern oil exploration: that petroleum comes from the heating of organic material over time in Earth’s shallower crust.

[263] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 10: “The modern petroleum industry began in the later years of the 1850s with the discovery, in 1857, and subsequent commercialization of petroleum in Pennsylvania in 1859…. The modern refining era can be said to have commenced in 1862 with the first appearance of petroleum distillation….”

Page 12: “After completion of the first well (by Edwin Drake [in 1857]) the surrounding areas were immediately leased and extensive drilling took place. Crude oil output in the United States increased from approximately 2000 barrels … in 1859 to nearly 3,000,000 bbl in 1863 and approximately 10,000,000 barrels in 1874. In 1861 the first cargo of oil, contained in wooden barrels, was sent across the Atlantic to London, and by the 1870s, refineries, tank cars, and pipelines had become characteristic features of the industry….”

[264] Report: “Year-in-Review: 2012, Energy Infrastructure Events and Expansions.” U.S. Department of Energy, July 2013. <energy.gov>

Page 16: “Crude oil and petroleum products are largely transported by marine vessels and pipelines. These assets deliver the vast majority of the world’s crude oil supply, including that of the United States.”

[265] Report: “Overview of the Design, Construction, and Operation of Interstate Liquid Petroleum Pipelines.” By T.C. Pharris and R.L. Kolpa. Argonne National Laboratory, Environmental Science Division, November 2007. <corridoreis.anl.gov>

Page 1:

The U.S. liquid petroleum pipeline industry is large, diverse, and vital to the nation’s economy. Comprised of approximately 200,000 miles of pipe in all fifty states, liquid petroleum pipelines carried more than 40 million barrels per day, or 4 trillion barrel-miles, of crude oil and refined products during 2001. That represents about 17% of all freight transported in the United States, yet the cost of doing so amounted to only 2% of the nation’s freight bill. Approximately 66% of domestic petroleum transport (by ton-mile) occurs by pipeline, with marine movements accounting for 28% and rail and truck transport making up the balance. In 2004, the movement of crude petroleum by domestic federally regulated pipelines amounted to 599.6 billion ton-miles, while that of petroleum products amounted to 315.9 billion ton-miles (AOPL 2006). As an illustration of the low cost of pipeline transportation, the cost to move a barrel of gasoline from Houston, Texas, to New York Harbor is only 3¢ per gallon, which is a small fraction of the cost of gasoline to consumers.

[266] Report: “Biofuels: Challenges to the Transportation, Sale, and Use of Intermediate Ethanol Blends.” U.S. Government Accountability Office, June 2011. <www.gao.gov>

Page 6:

As shown in figure 2, the infrastructure used to transport petroleum fuels from refineries to wholesale terminals in the United States is different from that used to transport ethanol. Petroleum-based fuel is primarily transported from refineries to terminals by pipeline.10

10Terminals on the East Coast are large integrated facilities with marine, pipeline, and tanker truck receiving and dispatching capabilities. Although some terminals have rail access, they were not originally designed to support rail as a major mode for transporting fuel.

Page 7:

Figure 2: Primary Transportation of Petroleum Products and Ethanol from Refineries to Retail Fueling Outlets

Petroleum and Ethanol Transportation

Note: Other means of transportation are also used to move petroleum and ethanol products to wholesale terminals. For example, for ethanol, barges are also used to a limited extent.

Page 16: “Over many decades, the United States has established very efficient networks of pipelines that move large volumes of petroleum-based fuels from production or import centers on the Gulf Coast and in the Northeast to distribution terminals along the coasts.”

[267] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 138: “Large-scale transportation of crude oil, refined petroleum products, and natural gas is usually accomplished by pipelines and tankers, whereas smaller-scale distribution, especially of petroleum products, is carried out by barges, trucks, and rail cars.”

[268] Webpage: “Safe Pipelines FAQs.” U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, August 29, 2007. <www.phmsa.dot.gov>

Pipelines are one of the safest and most cost-effective means to transport the extraordinary volumes of natural gas and hazardous liquid products that fuel our economy. To move the volume of even a modest pipeline, it would take a constant line of tanker trucks, about 750 per day, loading up and moving out every two minutes, 24 hours a day, seven days a week. The railroad-equivalent of this single pipeline would be a train of seventy-five 2,000-barrel tank rail cars everyday.

Relative to the volumes of products transported, pipelines are extremely safe when compared to other modes of energy transportation. Oil pipeline spills amount to about 1 gallon per million barrel-miles (Association of Oil Pipelines). One barrel, transported one mile, equals one barrel-mile, and there are 42 gallons in a barrel. In household terms, this is less than one teaspoon of oil spilled per thousand barrel-miles.

Pipeline statistics for calendar year 2002 report 139 liquid pipeline accidents resulted in the loss of about 97,000 barrels and about $31 million in property damage, but no deaths nor injuries. Natural gas transmission line accidents in 2002 resulted in one death and five injuries. …

Even though pipeline transportation is the safest and most economical means of transportation for our nation’s energy products, PHMSA and pipeline operators are engaged in research to identify and develop more effective means of ensuring the safety of energy pipelines.

[269] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Crude Oil: … Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.”

[270] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 3: “Petroleum products are the basic materials used for the manufacture of synthetic fibers for clothing and in plastics, paints, fertilizers, insecticides, soap, and synthetic rubber. The uses of petroleum as a source of raw material in manufacturing are central to the functioning of modern industry.”

[271] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Petroleum1 [=] 35% … Transportation [=] 92% … Industrial5 [=] 39% … Residential and Commercial6 [=] 15%6 … Electric Power7 [=] 1% …

1 Does not include biofuels that have been blended with petroleum—biofuels are included in “Renewable Energy.” …

5 Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants.

6 Includes commercial combined-heat-and-power (CHP) and commercial electricity-only plants.

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. Includes 0.2 quadrillion Btu of electricity net imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[272] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 49: “Table 3.1: Petroleum Overview (Thousand Barrels per Day)”

NOTE: An Excel file containing the data and calculations is available upon request.

[273] Webpage: “Oil: Crude and Petroleum Products Explained, Oil Imports and Exports—Basics.” U.S. Energy Information Administration. Last updated June 9, 2015. <www.eia.gov>

U.S. dependence on imported petroleum has declined since peaking in 2005. This trend is the result of a variety of factors including a decline in consumption and shifts in supply patterns. The economic downturn following the financial crisis of 2008, improvements in efficiency, changes in consumer behavior, and patterns of economic growth all contributed to the decline in petroleum consumption. Additionally, increased use of domestic biofuels (ethanol and biodiesel) and strong gains in domestic production of crude oil and natural gas plant liquids expanded domestic supplies and reduced the need for imports.

NOTE: This webpage includes renewable fuels in the totals for petroleum products. In keeping with the precise definition of petroleum and EIA’s data on “Primary Energy Consumption by Source and Sector” (cited above), Just Facts does not include renewable fuels in the totals for petroleum products.

[274] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 37: “Because of increased domestic production, net imports of natural gas, crude oil, and petroleum products have declined markedly from a peak of about 12.5 million barrels a day in 2005 to roughly 7.7 million in 2012. Besides higher domestic production, the decline in net imports reflects the impact of high oil prices on consumption.”

[275] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 49: “Table 3.1: Petroleum Overview (Thousand Barrels per Day)”

NOTE: An Excel file containing the data and calculations is available upon request.

[276] Dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, January 29, 2016. <www.eia.gov>

NOTES:

- An Excel file containing the data and calculations is available upon request.

- The sum total of net imports from certain combinations of nations can be more than 100%, because “there are many countries where we send more than we receive, so our net imports with these countries is negative. If you included all of the countries, those with positive net imports and those with negative net imports, you would get something that added up to 100%.” [Email from the U.S. Energy Information Administration to Just Facts on March 8, 2016.]

[277] Dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, January 29, 2016. <www.eia.gov>

NOTES:

- An Excel file containing the data and calculations is available upon request.

- The sum total of net imports from certain combinations of nations can be more than 100%, because “there are many countries where we send more than we receive, so our net imports with these countries is negative. If you included all of the countries, those with positive net imports and those with negative net imports, you would get something that added up to 100%.” [Email from the U.S. Energy Information Administration to Just Facts on March 8, 2016.]

[278] Dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, January 29, 2016. <www.eia.gov>

NOTES:

- An Excel file containing the data and calculations is available upon request.

- The sum total of net imports from certain combinations of nations can be more than 100%, because “there are many countries where we send more than we receive, so our net imports with these countries is negative. If you included all of the countries, those with positive net imports and those with negative net imports, you would get something that added up to 100%.” [Email from the U.S. Energy Information Administration to Just Facts on March 8, 2016.]

[279] Webpage: “Our Mission.” Organization of the Petroleum Exporting Countries, 2016. <www.opec.org>

“In accordance with its Statute, the mission of the Organization of the Petroleum Exporting Countries (OPEC) is to coordinate and unify the petroleum policies of its Member Countries and ensure the stabilization of oil markets in order to secure an efficient, economic and regular supply of petroleum to consumers, a steady income to producers and a fair return on capital for those investing in the petroleum industry.”

[280] Webpage: “Member Countries.” Organization of the Petroleum Exporting Countries, 2016. <www.opec.org>

The Organization of the Petroleum Exporting Countries (OPEC) was founded in Baghdad, Iraq, with the signing of an agreement in September 1960 by five countries namely Islamic Republic of Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. They were to become the Founder Members of the Organization.

These countries were later joined by Qatar (1961), Indonesia (1962), Libya (1962), the United Arab Emirates (1967), Algeria (1969), Nigeria (1971), Ecuador (1973), Gabon (1975) and Angola (2007).

From December 1992 until October 2007, Ecuador suspended its membership. Gabon terminated its membership in 1995. Indonesia suspended its membership in January 2009, but this was reactivated from 1st January 2016.

This means that, currently, the Organization has a total of 13 Member Countries.

[281] Statue: “OPEC Statue.” Organization of the Petroleum Exporting Countries, December 11, 2012. <www.opec.org>

Page 1:

Article 1

The Organization of the Petroleum Exporting Countries (OPEC), hereinafter referred to as “the Organization”, created as a permanent intergovernmental organization in conformity with the Resolutions of the Conference of the Representatives of the Governments of Iran, Iraq, Kuwait, Saudi Arabia and Venezuela, held in Baghdad from September 10 to 14, 1960, shall carry out its functions in accordance with the provisions set forth hereunder.

Article 2

A. The principal aim of the Organization shall be the coordination and unification of the petroleum policies of Member Countries and the determination of the best means for safeguarding their interests, individually and collectively. …

C. Due regard shall be given at all times to the interests of the producing nations and to the necessity of securing a steady income to the producing countries; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on their capital to those investing in the petroleum industry.

[282] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 30: “The key factors determining long-term supply, demand, and prices for petroleum and other liquids can be summarized in four broad categories: the economics of non-Organization of the Petroleum-Exporting Countries (OPEC) petroleum liquids supply; OPEC investment and production decisions; the economics of other liquids supply; and world demand for petroleum and other liquids.”

Page 31: “Although the OPEC resource base is sufficient to support much higher production levels, the OPEC countries have an incentive to restrict production in order to support higher prices and sustain revenues in the long term. The Reference case assumes that OPEC will maintain a cohesive policy of limiting supply growth, rather than maximizing total annual revenues.”

[283] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Pages 344–345:

14.3.3 Analysis of the OPEC Behaviour

There is a vast literature analyzing the OPEC behaviour and strategies…. As usual in such an area, there is no consensus about how best OPEC can be described. This difficulty arises because OPEC has followed different strategies at different times to determine prices and production levels (Fattouh 2007). …

The models on OPEC behaviour can be categorized into broad groups of models: (a) cartel models such as the dominant firm model or (b) non-cartel models such as target revenue model, and the competitive model. …

14.3.3.1 Cartel Model

A cartel occurs when a group of firms or organizations enter into an agreement to control the market by fixing price and/or limiting supply through production quotas. A cartel may work in a number of ways: as if there is a single monopoly producer, or with market-sharing agreements. The objective is to reduce competition and thereby generate higher profits for the group. … [I]f the producers enter into an agreement to enforce a monopoly price (pm) in the market, they will have to agree to reduce supply… in such a way that the marginal revenue equals the marginal cost. Each member of the cartel then receives a higher price for the output but any producer will be interested to participate only if it can extract more benefits compared to a competitive environment. As long as this condition is satisfied, members will be happy to support the collusive behaviour.

[284] Textbook: Energy Economics: Concepts, Issues, Markets and Governance. By Subhes C. Bhattacharyya. Springer-Verlag, 2011.

Pages 347–348:

14.3.3.3 Limit Pricing Model

Limit pricing model examines the effect of changes in demand for cartel. Competition can arise from non-cartel producers as well as from other fuels. Producers outside the cartel affect the demand and supply. …

Two general strategies have been considered: an offensive strategy where the cartel declares the price war and another defensive strategy where the cartel conserves its resources leaving non-cartel producers freedom and space to operate in the market.

In the price war strategy, the cartel will try to drive the competitors out of the market. As the cartel benefits from cost advantage, it can forgo the market control strategy and let price drop down to the competitive level. At this point, costly producers who were benefiting from the price protection offered by the cartel will become non-competitive and will be displaced by cartel output. Hence, the cartel will see its market share increase but the price will reach the competitive market levels (see Fig. 14.23). The overall market supply will increase as well.

The cartel can adopt a defensive strategy when it faces competition from other substitutes that threaten the demand of the commodity under cartel control. Generally, such substitutes are viable when the price reaches a certain level where it becomes profitable for alternatives to appear. In such a case the cartel can decide to set the price below this threshold level where the profit for the cartel may not be maximized but it prevents entry of new substitutes. … OPEC has used both the strategies to ensure its control over the oil market.

[285] Report: “2015 World Oil Outlook.” Organization of the Petroleum Exporting Countries, October 20, 2015. <www.opec.org>

Page 5: “Since the publication of the 2014 edition of the WOO [World Oil Outlook] in November last year, the most obvious market development has been the oil price collapse. While the average price of the OPEC Reference Basket (ORB) during the first half of 2014 was over $100/barrel, it dropped to less than $60/b in December 2014 and has averaged close to $53/b in the first nine months of 2015.”

[286] Article: “Saudi Arabia’s Oil Strategy Tears OPEC Apart.” By John Defterios. CNN Money, January 15, 2016. <money.cnn.com>

The Vienna-based group of 13 producers is now a house deeply divided, and I would suggest, facing the worst internal crisis in its 55-year history. …

OPEC appears to be divided into two main camps: One has nine members—ranging from Algeria to Venezuela—who want to scrap the Saudi-led price war with non-OPEC producers.

The problem for them is that the four who want to continue the fight—Saudi Arabia, Kuwait, Qatar and the UAE—hold nearly all of OPEC’s spare capacity, so their votes inevitably carry more sway.

Also often overlooked is that OPEC only works by unanimous decision—making the effort to corral all members incredibly difficult at a time when their economies are hurting badly. …

Saudi Arabia opened the taps to bring prices lower, then dialed them back when oil collapsed to $40 a barrel. Prices then stabilized, but since then, the U.S. added four million barrels a day of production, which has been a global game changer.

Chris Faulkner, CEO of Dallas-based oil fracker Breitling Energy, is convinced OPEC will not reverse its stance even if U.S. output falls from a peak of 9.6 million barrels a day to an estimated 8 million by the end of 2016.

Faulkner says he constantly gets asked, “when is America going away?” in reference to shale production. The reality is the small and medium sized players are elastic and can rev back up if oil recovers and stabilizes at $50.

This is why the U.S. shale revolution, and Russia’s record output of nearly 11 million barrels a day, are creating unprecedented tension within OPEC.

[287] Article: “There’s One Place Where OPEC Can’t Broker an Oil Deal: Texas.” By Javier Blas and Dan Murtaugh. Bloomberg, February 16, 2016. <www.bloomberg.com>

Slowly but surely, low prices have been bringing the U.S. shale industry to its knees. Bankruptcies have mounted while company after company slashed spending, laid off roughnecks and idled drilling rigs. As many as 74 North American producers face significant difficulties in sustaining debt, according to credit rating firm Moody’s Investors Service.

The drop in U.S. oil rigs to the lowest level since 2010 is starting to translate to the wellhead. In North Dakota, production from the prolific Bakken formation suffered its first year-on-year drop in a decade in September. In Texas, home of the Eagle Ford and Permian basins, output in November fell on an annual basis the first time since 2010.

“Saudi Arabia needs to be assured that U.S. shale wouldn’t bounce back quickly,” said Bob McNally, president of consultant Rapidan Group in Washington and a former senior oil official at the White House.

[288] Transcript: “Outlook for Global Oil Markets.” Organization of the Petroleum Exporting Countries, January 25, 2016. <www.opec.org>

Opening address by HE Abdalla S. El-Badri, OPEC Secretary General, at the Chatham House Conference: Middle East and North Africa Energy 2016, Theme: “Power, Security and Energy Markets”, Overview: Energy Markets, Political Developments and Security Challenges, 25 January 2016, London, U.K.

The story of our industry is one of many cycles, both up and down. …

It is well documented that the cycle on this occasion has been supply-driven, with most of the supply increases in recent years coming from high-cost production. Until 2015, all of the supply growth since 2008 has come from non-OPEC countries. Between 2008 and 2014, overall non-OPEC growth was more than 6 million barrels a day, while OPEC actually saw a contraction.

In fact, in 2013 and 2014, OPEC supply fell by more than 1 million barrels a day and non-OPEC grew by 3.7 million barrels a day. To put this in some context, global demand growth over these two years was 2.3 million barrels a day. …

In 2015, this dynamic changed as expansion was seen from both non-OPEC and OPEC. Non-OPEC grew by slightly over 1.2 million barrels a day, and OPEC at around 1 million barrels a day. …

These numbers are important when we look at the growth in OECD [Organization for Cooperation and Economic Development] commercial stocks. … [T]he five-year average was at its lowest level at the end of 2013. Since then the five-year average has risen dramatically, from a negative level of 85 million barrels to a surplus of more than 260 million barrels at the end of 2015. There is no doubt this has strongly impacted crude prices.

Moreover, for the same period there has also been a rise in non-OECD inventories, plus an expansion in some non-OECD strategic petroleum reserves.

It is vital the market addresses the issue of the stock overhang. As you can see from previous cycles, once this overhang starts falling then prices start to rise.

Given how this developed, it should be viewed as something OPEC and non-OPEC tackle together. Yes, OPEC provided some of the additional supply last year, but the majority of this has come from Non-OPEC countries.

It is crucial that all major producers sit down to come up with a solution to this. The market needs to see inventories come down to levels that allow prices to recover and investments to return.

[289] Article: “Saudi Arabia, Russia to Freeze Oil Output Near Record Levels.” By Mohammed Sergie, Grant Smith, and Javier Blas. Bloomberg, February 16, 2016. <www.bloomberg.com>

Saudi Arabia and Russia agreed to freeze oil output at near-record levels, the first coordinated move by the world’s two largest producers to counter a slump that has pummeled economies, markets and companies.

While the deal is preliminary and doesn’t include Iran, it’s the first significant cooperation between OPEC and non-OPEC producers in 15 years and Saudi Arabia said it’s open to further action. …

The deal to fix production at January levels, which includes Qatar and Venezuela, is the “beginning of a process” that could require “other steps to stabilize and improve the market,” Saudi Oil Minister Ali Al-Naimi said in Doha Tuesday after the talks with Russian Energy Minster Alexander Novak. Qatar and Venezuela also agreed to participate, he said.

Saudi Arabia has resisted making any cuts in output to boost prices from a 12-year low, arguing that it would simply be losing market share unless its rivals also agreed to reduce supplies. Naimi’s comments may continue to feed speculation that the world’s biggest oil producers will take action to revive prices.

[290] Calculated with data from:

a) Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 133: “Table 5.7: Petroleum Net Imports by Country of Origin, Selected Years, 1960-2011”

b) Dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, January 29, 2016. <www.eia.gov>

“Data 1: Net Imports of Total Crude Oil and Products into the U.S. by Country”

NOTE: A slight divergence exists between the datasets in the overlapping years of 1993 to 2011.

[291] Webpage: “Factors Affecting Gasoline Prices.” U.S. Energy Information Administration. Last reviewed February 22, 2016. <www.eia.gov>

… Crude oil prices are determined by both demand and supply. World economic growth is the most significant factor affecting demand. Oil prices often increase in response to disruptions in the international and domestic supply of crude oil. A major factor in oil supply is the Organization of the Petroleum Exporting Countries (OPEC), which can sometimes exert significant influence on oil prices by setting an upper production limit on its members. OPEC produced about 42% of the world’s crude oil from 2000 to 2014.

[292] Webpage: “Spot Prices.” U.S. Energy Information Administration. Accessed February 25, 2016 at <www.eia.gov>

Crude oil is traded in a global market. Prices of the many crude oil streams produced globally tend to move closely together, although there are persistent differentials between light-weight, low-sulfur (light-sweet) grades and heavier, higher-sulfur (heavy-sour) crudes that are lower in quality. …

Both crude oil and petroleum product prices can be affected by events that have the potential to disrupt the flow of oil and products to market, including geopolitical and weather-related developments. These types of events may lead to actual disruptions or create uncertainty about future supply or demand, which can lead to higher volatility in prices. The volatility of oil prices is inherently tied to the low responsiveness or “inelasticity” of both supply and demand to price changes in the short run. Both oil production capacity and the equipment that use petroleum products as their main source of energy are relatively fixed in the near-term. It takes years to develop new supply sources or vary production, and it is very hard for consumers to switch to other fuels or increase fuel efficiency in the near- term when prices rise. Under such conditions, a large price change can be necessary to re-balance physical supply and demand following a shock to the system.

Much of the world’s crude oil is located in regions that have been prone historically to political upheaval, or have had their oil production disrupted due to political events. Several major oil price shocks have occurred at the same time as supply disruptions triggered by political events, most notably the Arab Oil Embargo in 1973-74, the Iranian revolution and Iran-Iraq war in the late 1970s and early 1980s, and Persian Gulf War in 1990. More recently, disruptions to supply (or curbs on potential development of resources) from political events have been seen in Nigeria, Venezuela, Iraq, Iran, and Libya. …

Weather can also play a significant role in oil supply. Hurricanes in 2005, for example, shut down oil and natural gas production as well as refineries. As a result, petroleum product prices increased sharply as supplies to the market dropped. Severely cold weather can strain product markets as producers attempt to supply enough of the product, such as heating oil, to consumers in a short amount of time, resulting in higher prices. Other events such as refinery outages or pipeline problems can restrict the flow of oil and products, driving up prices.

However, the influence of these types of factors on oil prices tends to be relatively short lived. Once the problem subsides and oil and product flows return to normal, prices usually return to previous levels.

[293] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fpc.state.gov>

Pages 3-5:

Why Crude Oil Prices Increased

Figure 1 shows how rising crude prices in the first half of 2011 corresponded to higher gasoline prices.8 That increase was due at least in part to unrest in Libya and elsewhere in the Middle East and North Africa. In early 2012, developments around Iran and their implications for global oil supply have been a key factor in recent oil and gasoline price changes. Sustained demand growth in emerging economies and several other factors have also played a role.

A series of developments around Iran are likely contributing to higher crude oil prices. The EU elected to ban Iranian oil imports by July 1, 2012. Additional U.S. and EU sanctions have made it more difficult for Iran’s customers to finance and insure Iranian crude shipments.9 Japan, South Korea and others are reducing imports of Iranian crude to avoid U.S. sanctions on foreign banks that deal with Iran’s Central Bank.10 Iran’s largest customers, China and India, have publicly rejected non-U.N. sanctions. China reduced imports from Iran in January 2012; this may have been to press for a discount on oil.11 India reportedly increased imports in January, and has negotiated to pay for some Iranian imports in Indian rupees instead of dollars.12 However, some Indian companies may be having difficulties finding shippers willing to transport crude from Iran.13 For more on Iran sanctions, see CRS Report RS20871, Iran Sanctions, by Kenneth Katzman. Tightening sanctions have prompted Iranian officials to threaten closing the Strait of Hormuz, a critical thoroughfare of the global oil trade. For more about this, see CRS Report R42335, Iran’s Threat to the Strait of Hormuz, coordinated by Kenneth Katzman and Neelesh Nerurkar.

Developments that reduce, reshuffle, or create risks to oil supply can contribute to higher crude oil prices. Those no longer buying Iranian crude oil are looking for supplies from elsewhere, potentially bidding up the cost of oil. Those who continue to buy crude from Iran may be able to negotiate a discount as Iran has fewer customers to choose from, but it is unclear whether the Iranians have been willing to offer such a discount, though they do appear ready to be flexible on other payment terms, such as currency. If these adjustments take place, it could reduce pressure on global oil prices. If instead Iranian oil supply is shut-in as a result of Iran not being able to find buyers, this could reduce global oil supply and create a more durable impact on global oil prices.

There are additional concerns about the adequacy of global supply. Unrest has reduced production from several smaller producers in recent months, including South Sudan, Yemen, and Syria.14 Oil production from the newly independent Republic of South Sudan has shut down due to transit fee disputes with the Republic of Sudan (North Sudan).15 Saudi Arabia, which holds most of the world’s spare oil production capacity, has stated that it stands ready to make up for supply disruptions elsewhere. However, some worry that Saudi Arabia does not have as much spare capacity as it claims (others disagree), and there is concern that if oil trade through the Strait of Hormuz were disrupted, that this additional Saudi supply would have little way to reach international markets.16

While global oil supply is slated to grow from numerous sources, including from the United States, new production takes time. In the short run, oil supply is inelastic to prices, which means supply is slow to ramp up in the face of an oil price spike, even if it makes such production profitable. There is a long lead time for investment to yield higher output. (Some investors may fear that prices may have eased by the time the new oil is actually produced.) The exception is oil produced from existing spare capacity, which is mostly held by Saudi Arabia, as mentioned earlier.

Meanwhile, global demand has reached new highs. According to EIA, global oil consumption is expected to grow at an above trend rate, led entirely by emerging economies, despite rising oil prices.17 Some such as China continue to experience strong oil demand growth, due largely to their rapidly expanding economies. Several one-off events may also be contributing to a tighter supply demand balance: Japan is using more oil in power generation to offset nuclear outages and China may be adding crude oil to its own new strategic petroleum stockpile.18 European oil demand was boosted in February 2012 due to colder weather.19

Global developments may be difficult to understand from the U.S. perspective, where oil production is rising, demand growth remains weak, and no oil is imported from Iran. However, the market for oil is globally integrated; events anywhere can affect oil prices. The United States imported almost no oil from Libya prior to unrest there in 2011. However, when refineries elsewhere that did buy Libyan crude had to find oil from elsewhere, they bid up global oil prices. A similar effect may be taking place as customers shift away from Iranian oil. While U.S. imports have declined in recent years, the United States remains the world’s largest oil importer.20 Further, recent positive economic data for the United States point to a recovering economy,21 which also may mean recovering demand for gasoline and other oil products. Just as concerns about future supply disruptions can drive up prices, so too can concerns that oil demand will be greater than previously anticipated.

[294] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 34:

A strong rebound in gas and then oil production in the United States over the past few years has taken markets and policymakers by surprise…. As a result …. light sweet crude oil from the landlocked production areas in the U.S. Midwest is selling at an unusually large discount from international benchmark prices. …

The surge in production is largely the result of the new ability of producers to extract oil and gas from unconventional geological formations—so-called shale rock and tight rock or sand formations.

Page 37: “[T]he shale revolution highlights the reality that price incentives and technological change can trigger important supply responses in the oil and gas sector and that supply constraints can change over time.”

[295] Calculated with data from:

a) Report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 133: “Table 9.1: Crude Oil Price Summary (Dollarsa per Barrel)”

Page 135: “Table 9.3 Landed Costs of Crude Oil Imports From Selected Countries (Dollarsa per Barrel)”

On this table, “Total OPEC” for all years includes Algeria, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela; for 1973–2008, also includes Indonesia; for 1973–1992 and again beginning in 2008, also includes Ecuador (although Ecuador rejoined OPEC in November 2007, on this table Ecuador is included in “Total Non-OPEC” for 2007); for 1974–1995, also includes Gabon (although Gabon was a member of OPEC for only 1975–1994); and beginning in 2007, also includes Angola. Data for all countries not included in” Total OPEC” are included in “Total Non-OPEC” [Canada, Colombia, Mexico, Nigeria, United Kingdom].

b) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

Pages 71–74: “Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U.S. city average, all items (1982-84=100, unless otherwise noted)”

NOTE: An Excel file containing the data and calculations is available upon request.

[296] Calculated with data from:

a) Report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 133: “Table 9.1: Crude Oil Price Summary (Dollarsa per Barrel)”

Page 135: “Table 9.3 Landed Costs of Crude Oil Imports From Selected Countries (Dollarsa per Barrel)”

On this table, “Total OPEC” for all years includes Algeria, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela; for 1973–2008, also includes Indonesia; for 1973–1992 and again beginning in 2008, also includes Ecuador (although Ecuador rejoined OPEC in November 2007, on this table Ecuador is included in “Total Non-OPEC” for 2007); for 1974–1995, also includes Gabon (although Gabon was a member of OPEC for only 1975–1994); and beginning in 2007, also includes Angola. Data for all countries not included in” Total OPEC” are included in “Total Non-OPEC” [Canada, Colombia, Mexico, Nigeria, United Kingdom].

b) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

Pages 71–74: “Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U.S. city average, all items (1982-84=100, unless otherwise noted)”

NOTE: An Excel file containing the data and calculations is available upon request.

[297] Webpage: “Factors Affecting Gasoline Prices.” U.S. Energy Information Administration. Last reviewed February 22, 2016. <www.eia.gov>

“What do we pay for in a gallon of Regular Grade gasoline … 2015 Average Retail Price: $2.42 … Distribution & Marketing [=] 14% … Refining Costs and Profits [=] 19% … Federal And State Taxes [=] 19% … Crude Oil [=] 48%”

[298] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Crude Oil: A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Depending upon the characteristics of the crude stream, it may also include: 1) small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric pressure after being recovered from oil well (casinghead) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included; 2) small amounts of nonhydrocarbons produced with the oil, such as sulfur and various metals; and 3) drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale. Liquids produced at natural gas processing plants are excluded.

[299] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Pages 5: “Oil and natural gas are found in a variety of geologic formations. Conventional oil and natural gas are found in deep, porous rock or reservoirs and can flow under natural pressure to the surface after drilling.”

[300] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35: “Oil and gas have long been produced from what are now called ‘conventional sources’: wells are drilled into the earth’s surface, and pressure that is naturally present in the field—possibly with help from pumps—is used to bring the fuel to the surface.”

[301] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

“[F]or the purposes of this report, we use the term ‘shale oil’ to refer to oil from shale and other tight formations, which is recoverable by hydraulic fracturing and horizontal drilling techniques and is described by others as ‘tight oil’.”

NOTE: See the difference in the definitions between this footnote and the one below.

[302] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Although the terms shale oil2 and tight oil are often used interchangeably in public discourse, shale formations are only a subset of all low permeability tight formations, which include sandstones and carbonates, as well as shales, as sources of tight oil production. Within the United States, the oil and natural gas industry typically refers to tight oil production rather than shale oil production, because it is a more encompassing and accurate term with respect to the geologic formations producing oil at any particular well. EIA has adopted this convention, and develops estimates of tight oil production and resources in the United States that include, but are not limited to, production from shale formations.

[303] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 82: “The term tight oil does not have a specific technical, scientific, or geologic definition. Tight oil is an industry convention that generally refers to oil produced from very-low-permeability (138) shale, sandstone, and carbonate formations. Some of these geologic formations have been producing low volumes of oil for many decades in limited portions of the formation.”

[304] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1: “Shale is a sedimentary rock that is predominantly composed of consolidated clay-sized particles.”

Pages 5-6:

In contrast to the free-flowing resources found in conventional formations, the low permeability of some formations, including shale, means that oil and gas trapped in the formation cannot move easily within the rock. … [T]o extract shale oil and gas from the rock, fluids and proppants (usually sand or ceramic beads used to hold fractures open in the formation) are injected under high pressure to create and maintain fractures to increase permeability, thus allowing oil or gas to be extracted. Other formations, such as coalbed methane formations and tight sandstone formations,12 may also require stimulation to allow oil or gas to be extracted.13

The process to develop shale oil and gas is similar to the process for conventional onshore oil and gas, but shale formations may rely on the use of horizontal drilling and hydraulic fracturing—which may or may not be used on conventional wells.

12Conventional sandstone has well-connected pores, but tight sandstone has irregularly distributed and poorly connected pores. Due to this low connectivity or permeability, gas trapped within tight sandstone is not easily produced.

13For coalbed methane formations, the reduction in pressure needed to extract gas is achieved through dewatering. As water is pumped out of the coal seams, reservoir pressure decreases, allowing the natural gas to release (desorb) from the surface of the coal and flow through natural fracture networks into the well.

[305] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35:

Other geological structures in the United States—shale rock and tight sand formations—have long been known to contain oil and gas. But the fuels are trapped in these formations and cannot be extracted in the same way as from conventional sources. Instead, producers use a combination of horizontal drilling and hydraulic fracturing, or “fracking,” during which fluids are injected under high pressure to break up the formations and release trapped fossil fuels.

[306] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “[T]he production of shale oil requires that at least 15 percent to 25 percent of the pore fluids be in the form of natural gas so that there is sufficient gas-expansion to drive the oil to the well-bore. In the absence of natural gas to provide reservoir drive, shale oil production is problematic and potentially uneconomic at a low production rate.”

[307] Webpage: “About Tar Sands.” Oil Shale and Tar Sands Programmatic Environmental Impact Statement Information Center, U.S. Department of the Interior, Bureau of Land Management. Accessed August 29, 2013 at <ostseis.anl.gov>

Tar sands (also referred to as oil sands) are a combination of clay, sand, water, and bitumen, a heavy black viscous oil. Tar sands can be mined and processed to extract the oil-rich bitumen, which is then refined into oil. The bitumen in tar sands cannot be pumped from the ground in its natural state; instead tar sand deposits are mined, usually using strip mining or open pit techniques, or the oil is extracted by underground heating with additional upgrading.

Tar sands are mined and processed to generate oil similar to oil pumped from conventional oil wells, but extracting oil from tar sands is more complex than conventional oil recovery. Oil sands recovery processes include extraction and separation systems to separate the bitumen from the clay, sand, and water that make up the tar sands. Bitumen also requires additional upgrading before it can be refined. Because it is so viscous (thick), it also requires dilution with lighter hydrocarbons to make it transportable by pipelines.

Much of the world’s oil (more than 2 trillion barrels) is in the form of tar sands, although it is not all recoverable. While tar sands are found in many places worldwide, the largest deposits in the world are found in Canada (Alberta) and Venezuela, and much of the rest is found in various countries in the Middle East. In the United States, tar sands resources are primarily concentrated in Eastern Utah, mostly on public lands. The in-place tar sands oil resources in Utah are estimated at 12 to 19 billion barrels.

[308] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Bitumen: A naturally occurring viscous mixture, mainly of hydrocarbons heavier than pentane, that may contain sulphur compounds and that, in its natural occurring viscous state, is not recoverable at a commercial rate through a well.

[309] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “[Shale oil] is not to be confused with oil shale, which is a sedimentary rock with solid organic content (kerogen) but no resident oil and natural gas fluids.”

[310] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 26: “Oil shale is a sedimentary rock containing solid organic material that converts into a type of crude oil only when heated.”

Page 5: “[T]he hydrocarbon trapped in the [oil] shale will not reach a liquid form without first being heated to very high temperatures—ranging from about 650 to 1,000 degrees Fahrenheit—in a process known as retorting.”

[311] Webpage: “About Oil Shale.” Oil Shale and Tar Sands Programmatic Environmental Impact Statement Information Center, U.S. Department of the Interior, Bureau of Land Management. Accessed August 29, 2013 at <ostseis.anl.gov>

Oil shale can be mined and processed to generate oil similar to oil pumped from conventional oil wells; however, extracting oil from oil shale is more complex than conventional oil recovery and currently is more expensive. The oil substances in oil shale are solid and cannot be pumped directly out of the ground. The oil shale must first be mined and then heated to a high temperature (a process called retorting); the resultant liquid must then be separated and collected. An alternative but currently experimental process referred to as in situ retorting involves heating the oil shale while it is still underground, and then pumping the resulting liquid to the surface. …

While oil shale has been used as fuel and as a source of oil in small quantities for many years, few countries currently produce oil from oil shale on a significant commercial level. Many countries do not have significant oil shale resources, but in those countries that do have significant oil shale resources, the oil shale industry has not developed because historically, the cost of oil derived from oil shale has been significantly higher than conventional pumped oil. The lack of commercial viability of oil shale-derived oil has in turn inhibited the development of better technologies that might reduce its cost.

Relatively high prices for conventional oil in the 1970s and 1980s stimulated interest and some development of better oil shale technology, but oil prices eventually fell, and major research and development activities largely ceased. More recently, prices for crude oil have again risen to levels that may make oil shale-based oil production commercially viable, and both governments and industry are interested in pursuing the development of oil shale as an alternative to conventional oil. …

Oil shale can be mined using one of two methods: underground mining using the room-and-pillar method or surface mining. After mining, the oil shale is transported to a facility for retorting, a heating process that separates the oil fractions of oil shale from the mineral fraction. The vessel in which retorting takes place is known as a retort. After retorting, the oil must be upgraded by further processing before it can be sent to a refinery, and the spent shale must be disposed of. Spent shale may be disposed of in surface impoundments, or as fill in graded areas; it may also be disposed of in previously mined areas. Eventually, the mined land is reclaimed. Both mining and processing of oil shale involve a variety of environmental impacts, such as global warming and greenhouse gas emissions, disturbance of mined land, disposal of spent shale, use of water resources, and impacts on air and water quality. The development of a commercial oil shale industry in the United States would also have significant social and economic impacts on local communities. Other impediments to development of the oil shale industry in the United States include the relatively high cost of producing oil from oil shale (currently greater than $60 per barrel), and the lack of regulations to lease oil shale.

[312] Report: “Oil shale and nahcolite resources of the Piceance Basin, Colorado.” U.S. Department of the Interior, U.S. Geological Survey, Oil Shale Assessment Team, 2010. <pubs.usgs.gov>

Chapter 1: “An Assessment of In-Place Oil Shale Resources in the Green River Formation, Piceance Basin, Colorado.” By Ronald C. Johnson, Tracey J. Mercier, Michael E. Brownfield, Michael P. Pantea, and Jesse G. Self. <pubs.usgs.gov>

Page 5: “This assessment does not attempt to estimate the amount of oil that is economically recoverable, largely because there has not been an economic method developed to recover oil from Green River oil shale.”

[313] Report: “Drilling Sideways—A Review of Horizontal Well Technology and Its Domestic Application.” U.S. Energy Information Administration, April 1993. <www.eia.gov>

Page viii:

The technical objective of horizontal drilling is to expose significantly more reservoir rock to the well bore surface than can be achieved via drilling of a conventional vertical well. The desire to achieve this objective stems from the intended achievement of other, more important technical objectives that relate to specific physical characteristics of the target reservoir, and that provide economic benefits. Examples of these technical objectives are the need to intersect multiple fracture systems within a reservoir and the need to avoid unnecessarily premature water or gas intrusion that would interfere with oil production. In both examples, an economic benefit of horizontal drilling success is increased productivity of the reservoir. In the latter example, prolongation of the reservoir’s commercial life is also an economic benefit.

… Significant successes include many horizontal wells drilled into the fractured Austin Chalk of Texas’ Giddings Field, which have produced at 2.5 to 7 times the rate of vertical wells, wells drilled into North Dakota’s Bakken Shale, from which horizontal oil production increased from nothing in 1986 to account for 10 percent of the State’s 1991 production, and wells drilled into Alaska’s North Slope fields.

Page 1:

A widely accepted definition of what qualifies as horizontal drilling has yet to be written. The following combines the essential components of two previously published definitions:1

Horizontal drilling is the process of drilling and completing, for production, a well that begins as a vertical or inclined linear bore which extends from the surface to a subsurface location just above the target oil or gas reservoir called the “kickoff point,” then bears off on an arc to intersect the reservoir at the “entry point,” and, thereafter, continues at a near-horizontal attitude tangent to the arc, to substantially or entirely remain within the reservoir until the desired bottom hole location is reached.

Most oil and gas reservoirs are much more extensive in their horizontal (areal) dimensions than in their vertical (thickness) dimension. By drilling that portion of a well which intersects such a reservoir parallel to its plane of more extensive dimension, horizontal drilling’s immediate technical objective is achieved. That objective is to expose significantly more reservoir rock to the wellbore surface than would be the case with a conventional vertical well penetrating the reservoir perpendicular to its plane of more extensive dimension (Figure 1). The desire to attain this immediate technical objective is almost always motivated by the intended achievement of more important objectives (such as avoidance of water production) related to specific physical characteristics of the target reservoir.

Pages 4-5:

Even when drilling technique has been optimized for a target, the expected financial benefits of horizontal drilling must at least offset the increased well costs before such a project will be undertaken. In successful horizontal drilling applications, the “offset or better” happens due to the occurrence of one or more of a number of factors.

First, operators often are able to develop a reservoir with a sufficiently smaller number of horizontal wells, since each well can drain a larger rock volume about its bore than a vertical well could. When this is the case, per well proved reserves are higher than for a vertical well. An added advantage relative to the environmental costs or land use problems that may pertain in some situations is that the aggregate surface “footprint” of an oil or gas recovery operation can be reduced by use of horizontal wells.

Second, a horizontal well may produce at rates several times greater than a vertical well, due to the increased wellbore surface area within the producing interval. For example, in the Austin Chalk reservoir of Texas’ Giddings Field, under equal pressure conditions, horizontal completions of 500 to 2,200 foot HD produce at initial rates 2½ to 7 times higher than vertical completions.7 Chairman Robert Hauptfuhrer of Oryx Energy Co. noted that “Our costs in the [Austin] chalk now are 50 percent more than a vertical well, but we have three to five or more times the daily production and reserves than a vertical well.”8 A faster producing rate translates financially to a higher rate of return on the horizontal project than would be achieved by a vertical project.

Third, use of a horizontal well may preclude or significantly delay the onset of production problems (interferences) that engender low production rates, low recovery efficiencies, and/or premature well abandonment, reducing or even eliminating, as a result of their occurrence, return on investment and total return.

Page 7: “Early production well drilling using horizontal techniques was subsequently undertaken by British Petroleum in Alaska’s Prudhoe Bay Field, in a successful attempt to minimize unwanted water and gas intrusions into the Sadlerochit reservoir.”

Page 13:

As noted previously, horizontal drilling is usually undertaken to achieve important technical objectives related to specific characteristics of a target reservoir. These characteristics typically involve:

• the reservoir rock’s permeability, which is its capacity to conduct fluid flow through the interconnections of its pore spaces (termed its “matrix permeability”), or through fractures (its “fracture permeability”), and/or

• the expected propensity of the reservoir to develop water or gas influxes deleterious to production, either from other parts of the reservoir or from adjacent rocks, as production takes place (an event called “coning”).

Due to its higher cost, horizontal drilling is currently restricted to situations where these characteristics indicate that vertical wells would not be as financially successful. In an oil reservoir which has good matrix permeability in all directions, no gas cap and no water drive, drilling of horizontal wells would likely be financial folly, since a vertical well program could achieve a similar recovery of oil at lower cost. But when low matrix permeability exists in the reservoir rock (especially in the horizontal plane), or when coning of gas or water can be expected to interfere with full recovery, horizontal drilling becomes a financially viable or even preferred current option. Most existing domestic applications of horizontal drilling reflect this “philosophy of application.”

[314] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “One reason why 3,000-to-5,000-foot horizontal laterals are employed in the United States is to increase the likelihood that a portion of the horizontal lateral will be sufficiently productive to make the well profitable.”

[315] Webpage: “Development of Radar Navigation and Radio Data Transmission for Microhole Coiled Tubing Bottomhole Assemblies.” U.S. Department of Energy, National Energy Technology Laboratory. Accessed August 27, 2013 at <netl.doe.gov>

[316] Report: “Drilling Sideways—A Review of Horizontal Well Technology and Its Domestic Application.” U.S. Energy Information Administration, April 1993. <www.eia.gov>

Page vii: “Horizontal drilling technology achieved commercial viability during the late 1980’s. Its successful employment, particularly in the Bakken Shale of North Dakota and the Austin Chalk of Texas, has encouraged testing of it in many domestic geographic regions and geologic situations.”

Pages 7-8:

The modern concept of non-straight line, relatively short-radius drilling, dates back at least to September 8, 1891, when the first U.S. patent for the use of flexible shafts to rotate drilling bits was issued to John Smalley Campbell (Patent Number 459,152). While the prime application described in the patent was dental, the patent also carefully covered use of his flexible shafts at much larger and heavier physical scales “… such, for example, as those used in engineer’s shops for drilling holes in boiler-plates or other like heavy work. The flexible shafts or cables ordinarily employed are not capable of being bent to and working at a curve of very short radius …”

The first recorded true horizontal oil well, drilled near Texon, Texas, was completed in 1929.9 Another was drilled in 1944 in the Franklin Heavy Oil Field, Venango County, Pennsylvania, at a depth of 500 feet.10 China tried horizontal drilling as early as 1957, and later the Soviet Union tried the technique.11 Generally, however, little practical application occurred until the early 1980’s, by which time the advent of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies, particularly downhole telemetry equipment, had brought some kinds of applications within the imaginable realm of commercial viability.

Early Commercial Horizontal Wells

Tests, which indicated that commercial horizontal drilling success could be achieved in more than isolated instances, were carried out between 1980 and 1983 by the French firm Elf Aquitaine in four horizontal wells drilled in three European fields: the Lacq Superieur Oil Field (2 wells) and the Castera Lou Oil Field, both located in southwestern France, and the Rospo Mare Oil Field, located offshore Italy in the Mediterranean Sea. In the latter instance, output was very considerably enhanced.12 Early production well drilling using horizontal techniques was subsequently undertaken by British Petroleum in Alaska’s Prudhoe Bay Field, in a successful attempt to minimize unwanted water and gas intrusions into the Sadlerochit reservoir.13

The Recent Growth of Commercial Horizontal Drilling Taking a cue from these initial successes, horizontal drilling has been undertaken with increasing frequency by more and more operators. They and the drilling and service firms that support them have expanded application of the technology to many additional types of geological and reservoir engineering factor-related drilling objectives. Domestic horizontal wells have now been planned and completed in at least 57 counties or offshore areas located in or off 20 States.

Horizontal drilling in the United States has thus far been focused almost entirely on crude oil applications. In 1990, worldwide, more than 1,000 horizontal wells were drilled. Some 850 of them were targeted at Texas’ Upper Cretaceous Austin Chalk Formation alone.

Page viii:

An offset to the benefits provided by successful horizontal drilling is its higher cost. But the average cost is going down. By 1990, the cost premium associated with horizontal wells had shrunk from the 300- percent level experienced with some early experimental wells to an annual average of 17 percent. Learning curves are apparent, as indicated by incurred costs, as new companies try horizontal drilling and as companies move to new target reservoirs. It is probable that the cost premium associated with horizontal drilling will continue to decline, leading to its increased use.

[317] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35: “[During fracking] fluids are injected under high pressure to break up the formations and release trapped fossil fuels.”

[318] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1: “[Hydraulic fracturing is] a process that injects a combination of water, sand, and chemical additives under high pressure to create and maintain fractures in underground rock formations that allow oil and natural gas to flow….”

Page 5: “[T]o extract shale oil and gas from the rock, fluids and proppants (usually sand or ceramic beads used to hold fractures open in the formation) are injected under high pressure to create and maintain fractures to increase permeability, thus allowing oil or gas to be extracted.”

Pages 9-13:

The next stage in the development process is stimulation of the shale formation using hydraulic fracturing. Before operators or service companies perform a hydraulic fracture treatment of a well, a series of tests may be conducted to ensure that the well, wellhead equipment, and fracturing equipment can safely withstand the high pressures associated with the fracturing process. Minimum requirements for equipment pressure testing can be determined by state regulatory agencies for operations on state or private lands. In addition, fracturing is conducted below the surface of the earth, sometimes several thousand feet below, and can only be indirectly observed. Therefore, operators may collect subsurface data—such as information on rock stresses20 and natural fault structures—needed to develop models that predict fracture height, length, and orientation prior to drilling a well. The purpose of modeling is to design a fracturing treatment that optimizes the location and size of induced fractures and maximizes oil or gas production.

To prepare a well to be hydraulically fractured, a perforating tool may be inserted into the casing and used to create holes in the casing and cement. Through these holes, fracturing fluid—that is injected under high pressures—can flow into the shale (fig. 2 shows a used perforating tool).

Fracturing fluids are tailored to site specific conditions, such as shale thickness, stress, compressibility, and rigidity. As such, the chemical additives used in a fracture treatment vary. Operators may use computer models that consider local conditions to design site-specific hydraulic fluids. The water, chemicals, and proppant used in fracturing fluid are typically stored on-site in separate tanks and blended just before they are injected into the well. Figure 3 provides greater detail about some chemicals commonly used in fracturing.

Figure 3: Examples of Common Ingredients Found in Fracturing Fluid

Fracking Fluid Ingredients

The operator pumps the fracturing fluid into the wellbore at pressures high enough to force the fluid through the perforations into the surrounding formation—which can be shale, coalbeds, or tight sandstone—expanding existing fractures and creating new ones in the process. After the fractures are created, the operator reduces the pressure. The proppant stays in the formation to hold open the fractures and allow the release of oil and gas. Some of the fracturing fluid that was injected into the well will return to the surface (commonly referred to as flowback) along with water that occurs naturally in the oil- or gas-bearing formation—collectively referred to as produced water. The produced water is brought to the surface and collected by the operator, where it can be stored on-site in impoundments, injected into underground wells, transported to a wastewater treatment plant, or reused by the operator in other ways.21 Given the length of horizontal wells, hydraulic fracturing is often conducted in stages, where each stage focuses on a limited linear section and may be repeated numerous times.

Once a well is producing oil or natural gas, equipment and temporary infrastructure associated with drilling and hydraulic fracturing operations is no longer needed and may be removed, leaving only the parts of the infrastructure required to collect and process the oil or gas and ongoing produced water. Operators may begin to reclaim the part of the site that will not be used by restoring the area to predevelopment conditions. Throughout the producing life of an oil or gas well, the operator may find it necessary to periodically restimulate the flow of oil or gas by repeating the hydraulic fracturing process. The frequency of such activity depends on the characteristics of the geologic formation and the economics of the individual well. If the hydraulic fracturing process is repeated, the site and surrounding area will be further affected by the required infrastructure, truck transport, and other activity associated with this process.

20Stresses in the formation generally define a maximum and minimum stress direction that influence the direction a fracture will grow.

21Underground injection is the predominant practice for disposing of produced water. In addition to underground injection, a limited amount of produced water is managed by discharging it to surface water, storing it in surface impoundments, and reusing it for irrigation or hydraulic fracturing.

[319] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “[T]he production of shale oil requires that at least 15 percent to 25 percent of the pore fluids be in the form of natural gas so that there is sufficient gas-expansion to drive the oil to the well-bore. In the absence of natural gas to provide reservoir drive, shale oil production is problematic and potentially uneconomic at a low production rate.”

[320] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

1940s Hydraulic fracturing first introduced to the petroleum industry.

1947 The first experimental hydraulic fracturing treatment conducted in Grant County, Kansas.

1949 The first commercial hydraulic fracturing treatment conducted in Stephens County, Oklahoma.

1950s Hydraulic fracturing becomes a commercially accepted process.

1955 More than 100,000 individual hydraulic fracturing treatments performed.

[321] Webpage: “Factors Affecting Gasoline Prices.” U.S. Energy Information Administration. Last reviewed February 6, 2013. <www.eia.gov>

In recent years, the world’s appetite for gasoline and diesel fuel grew so quickly that suppliers of these fuels had a difficult time keeping up with demand. This demand growth is a key reason why prices of both crude oil and gasoline reached record levels in mid-2008. …

… Crude oil prices are determined by both supply and demand factors. On the demand side of the equation, world economic growth is the biggest factor.

[322] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fpc.state.gov>

Page 4: “Meanwhile, global demand has reached new highs. According to EIA, global oil consumption is expected to grow at an above trend rate, led entirely by emerging economies, despite rising oil prices.17 Some such as China continue to experience strong oil demand growth, due largely to their rapidly expanding economies.”

[323] Article: “U.S. Oil Notches Record Growth.” By Keith Johnson and Russell Gold. Wall Street Journal, June 12, 2013. <online.wsj.com>

“While the U.S. gusher tamped down the effect of supply problems elsewhere, BP noted average oil prices remained at record-high levels last year. The prices reflect relentless demand for oil from developing countries, including China, India and most of the Middle East.”

[324] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1:

For decades, the United States has relied on imports of oil and natural gas to meet domestic needs. As recently as 2007, the expectation was that the nation would increasingly rely on imports of natural gas to meet its growing demand. However, recent improvements in technology have allowed companies that develop petroleum resources to extract oil and natural gas from shale formations,1 known as “shale oil” and “shale gas,” respectively, which were previously inaccessible because traditional techniques did not yield sufficient amounts for economically viable production.

Page 6:

The process to develop shale oil and gas is similar to the process for conventional onshore oil and gas, but shale formations may rely on the use of horizontal drilling and hydraulic fracturing—which may or may not be used on conventional wells. Horizontal drilling and hydraulic fracturing are not new technologies, as seen in figure 1, but advancements, refinements, and new uses of these technologies have greatly expanded oil and gas operators’ abilities to use these processes to economically develop shale oil and gas resources. For example, the use of multistage hydraulic fracturing within a horizontal well has only been widely used in the last decade.15

15Hydraulic fracturing is often conducted in stages. Each stage focuses on a limited linear section and may be repeated numerous times.

Page 7: “Late 1970s and early 1980s Shale formations, such as the Barnett in Texas and Marcellus in Pennsylvania, are known but believed to have essentially zero permeability and thus are not considered economic.”

Page 26: “Annual shale oil production in the United States increased more than fivefold, from about 39 million barrels in 2007 to about 217 million barrels in 2011…. This is because new technologies allowed more oil to be produced economically, and because of recent increases in the price for liquid petroleum that have led to increased investment in shale oil development.”

[325] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 34: “The sudden takeoff in the production of oil and gas from unconventional sources in recent years is another case in which high prices and new technologies combined to turn a previously uneconomical resource into an economically viable one.”

Page 35:

Both technologies [horizontal drilling and hydraulic fracturing] have been around for more than a half century, but until recently, using them cost more than the price of crude oil and natural gas.

This changed when prices began to rise sharply in recent years. Producers were able to profitably extract oil and gas from these [shale] formations. At the same time, improvements in horizontal drilling and fracking technologies reduced the cost of using them.

[326] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 2:

Crude oil production has increased since 2008, reversing a decline that began in 1986. From 5.0 million barrels per day in 2008, U.S. crude oil production increased to 6.5 million barrels per day in 2012. Improvements in advanced crude oil production technologies continues to lift domestic supply, with domestic production of crude oil increasing in the Reference case before declining gradually beginning in 2020 for the remainder of the projection period. The projected growth results largely from a significant increase in onshore crude oil production, particularly from shale and other tight formations, which has been spurred by technological advances and relatively high oil prices. Tight oil development is still at an early stage, and the outlook is highly uncertain. In some of the AEO2013 alternative cases, tight oil production and total U.S. crude oil production are significantly above their levels in the Reference case.

Page 33: “A key contributing factor to the recent decline in net import dependence has been the rapid growth of U.S. oil production from tight onshore formations, which has followed closely after the rapid growth of natural gas production from similar types of resources.”

CALCULATION: (6.5-5.0) / 5.0 = 0.3

[327] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 49: “Table 3.1: Petroleum Overview (Thousand Barrels per Day)”

NOTE: An Excel file containing the data and calculations is available upon request.

[328] Article: “Hydraulic fracturing accounts for about half of current U.S. crude oil production.” U.S. Energy Information Administration, March 15, 2016. <www.eia.gov>

Even though hydraulic fracturing has been in use for more than six decades, it has only recently been used to produce a significant portion of crude oil in the United States. This technique, often used in combination with horizontal drilling, has allowed the United States to increase its oil production faster than at any time in its history. Based on the most recent available data from states, EIA estimates that oil production from hydraulically fractured wells now makes up about half of total U.S. crude oil production.

[329] Report: “Annual Energy Outlook 2014 with Projections to 2040.” U.S. Energy Information Administration, April 2014. <www.eia.gov>

Page ES-2:

Key results highlighted in the AEO2014 [Annual Energy Outlook 2014] Reference and alternative cases include:

• Growing domestic production of natural gas and oil continues to reshape the U.S. energy economy, largely as a result of rising production from tight formations, but the effect could vary substantially depending on expectations about resources and technology. …

Growth in crude oil production from tight oil and shale formations supported by identification of resources and technology advances have supported a nearly fourfold increase in tight oil production from 2008, when it accounted for 12% of total U.S. crude oil production, to 2012, when it accounted for 35% of total U.S. production. …

In the Reference case, tight oil production begins to slow after 2021, contributing to a decline in total U.S. oil production through 2040. However, tight oil development is still at an early stage, and the outlook is uncertain. Changes in U.S. crude oil production depend largely on the degree to which technological advances allow production to occur in potentially high-yielding tight and shale formations.

[330] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Because they have proven to be quickly producible in large volumes at a relatively low cost, tight oil and shale gas resources have revolutionized U.S. oil and natural gas production, providing 29 percent of total U.S. crude oil production and 40 percent of total U.S. natural gas production in 2012. …

… The increase in U.S. crude oil production in 2012 of 847,000 barrels per day over 2011 was largely attributable to increased production from shales and other tight resources. …

… For example, U.S. crude oil production rose by 847,000 barrels per day in 2012, compared with 2011, by far the largest growth in crude oil production in any country. Production from shales and other tight plays accounted for nearly all of this increase, reflecting both the availability of recoverable resources and favorable above-the-ground conditions for production. …

The use of horizontal drilling in conjunction with hydraulic fracturing has greatly expanded the ability of producers to profitably produce oil and natural gas from low permeability geologic formations, particularly shale formations.

[331] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 34: “The surge in production is largely the result of the new ability of producers to extract oil and gas from unconventional geological formations—so-called shale rock and tight rock or sand formations. The revolution in production occurred first in natural gas and more recently in oil.”

[332] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 2: “Early drilling activity in shale formations was centered primarily on natural gas, but with the falling price of natural gas companies switched their focus to oil and natural gas liquids, which are a more valuable product.”

[333] Article: “U.S. Oil Notches Record Growth.” By Keith Johnson and Russell Gold. Wall Street Journal, June 12, 2013. <online.wsj.com>

“The fracking techniques that have unleashed so much crude in the U.S. haven’t yet had an impact overseas. However, recent government reports suggest that Argentina and Russia could have enormous deposits of crude oil accessible through fracking. Development of these resources has been slowed by government policies, competition from less expensive fields and a scarcity of specialized equipment.”

[334] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 37: “The full potential of the new resources at the global level is still unknown. Exploration and development outside the United States are only beginning.”

[335] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Key positive above-the-ground advantages in the United States and Canada that may not apply in other locations include private ownership of subsurface rights that provide a strong incentive for development; availability of many independent operators and supporting contractors with critical expertise and suitable drilling rigs and, preexisting gathering and pipeline infrastructure; and the availability of water resources for use in hydraulic fracturing.

[336] Article: “German Energy Push Runs Into Problems.” By Melissa Eddy. New York Times, March 19, 2014. <www.nytimes.com>

About 11 percent of Germany’s energy is provided by natural gas, of which 35 percent comes from Russia. Despite the German government’s assurances that reserves of natural gas held in storage tanks are sufficient to ensure continued supply, there are fears of shortages should Moscow decide to retaliate to Western sanctions by reducing the flow of natural gas to the West.

Germany has almost no natural gas of its own — at least not gas that can be extracted through conventional drilling techniques.

It does have potentially promising reserves of gas in shale rock. But extraction of that shale gas through the technique known as hydraulic fracturing, or fracking, does not feature in Germany’s current plans.

[337] Article: “Shale gas and tight oil are commercially produced in just four countries.” U.S. Energy Information Administration, February 13, 2015. <www.eia.gov>

“The United States, Canada, China, and Argentina are currently the only four countries in the world that are producing commercial volumes of either natural gas from shale formations (shale gas) or crude oil from tight formations (tight oil). The United States is by far the dominant producer of both shale gas and tight oil.”

[338] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Globally … 10 percent of estimated oil resources are in shale or tight formations. …

[I]t is important to distinguish between a technically recoverable resource, which is the focus of this report, and an economically recoverable resource. Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current technology, regardless of oil and natural gas prices and production costs. Economically recoverable resources are resources that can be profitably produced under current market conditions.

[339] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 33:

Estimates of technically recoverable resources from the rapidly developing tight oil formations are particularly uncertain and change over time as new information is gained through drilling, production, and technology experimentation. Over the past decade, as more tight and shale formations have gone into commercial production, estimates of technically and economically recoverable resources have generally increased. Technically recoverable resource estimates, however, embody many assumptions that might not prove to be true over the long term, over the entire range of tight or shale formations, or even within particular formations. For example, the tight oil resource estimates in the Reference case assume that production rates achieved in a limited portion of a given formation are representative of the entire formation, even though neighboring tight oil well production rates can vary widely. Any specific tight or shale formation can vary significantly across the formation with respect to relevant characteristics (72), resulting in widely varying rates of well production. The application of refinements to current technologies, as well as new technological advancements, can also have a significant but highly uncertain impact on the recoverability of tight and shale crude oil.

Page 34:

Although initial production rates have increased over the past few years, it is too early to conclude that overall EURs have increased and will continue to increase. Instead, producers may just be recovering the resource more quickly, resulting in a more dramatic decline in production later, with little impact on the well’s overall EUR. The decreased well spacing reflects less the capability to drill wells closer together (i.e., avoid interference) and instead more the discovery of and production from other shale plays that are not yet in commercial development. These may either be stacked in the same formation or reflect future technological innovations that would bring into production plays that are otherwise not amenable to current hydraulic fracturing technology.

Page 82: “Tight oil development is still at an early stage, and the outlook is highly uncertain. Alternative cases, including ones in which tight oil production is significantly above the Reference case projection, are examined in the ‘Issues in focus’ section of this report (see ‘Petroleum import dependence in a range of cases’).”

[340] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 21:

Overall, estimates of the size of technically recoverable shale oil resources in the United States are imperfect and highly dependent on the data, methodologies, model structures, and assumptions used. As these estimates are based on data available at a given point in time, they may change as additional information becomes available. Also these estimates depend on historical production data as a key component for modeling future supply. Because large-scale production of oil in shale formations is a relatively recent activity, their long-term productivity is largely unknown. For example, EIA estimated that the Monterey Shale in California may possess about 15.4 billion barrels of technically recoverable oil. However, without a longer history of production, the estimate has greater uncertainty than estimates based on more historical production data. At this time, USGS has not yet evaluated the Monterey Shale play.

[341] Report: “Oil and Gas Supply Module of the National Energy Modeling System: Model Documentation 2014.” U.S. Energy Information Administration, July 2014. <www.eia.gov>

Page 6: “Proved reserves are the estimated quantities that analyses of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.”

[342] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Economically recoverable resources are resources that can be profitably produced under current market conditions. The economic recoverability of oil and gas resources depends on three factors: the costs of drilling and completing wells, the amount of oil or natural gas produced from an average well over its lifetime, and the prices received for oil and gas production. Recent experience with shale gas in the United States and other countries suggests that economic recoverability can be significantly influenced by above-the-ground factors as well as by geology.

[343] Press release: “3 to 4.3 Billion Barrels of Technically Recoverable Oil Assessed in North Dakota and Montana’s Bakken Formation—25 Times More Than 1995 Estimate.” U.S. Department of the Interior, U.S. Geological Survey, April 10, 2008.

<www.usgs.gov>

“Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.”

[344] Report: “Oil and Gas Supply Module of the National Energy Modeling System: Model Documentation 2014.” U.S. Energy Information Administration, July 2014. <www.eia.gov>

Page 6: “Technically recoverable resources are those volumes considered to be producible with current recovery technology and efficiency but without reference to economic viability. Technically recoverable volumes include proved reserves and inferred reserves as well as undiscovered and other unproved resources. These resources may be recoverable by techniques considered either conventional or unconventional.”

[345] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current technology, regardless of oil and natural gas prices and production costs.”

[346] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Undiscovered Recoverable Reserves (Crude Oil and Natural Gas): Those economic resources of crude oil and natural gas, yet undiscovered, that are estimated to exist in favorable geologic settings.”

[347] Webpage: “Do we have enough oil worldwide to meet our future needs?” U.S. Energy Information Administration. Last updated December 9, 2014. <www.eia.gov>

An often cited, but misleading, measurement of future resource availability is the reserves-to-production ratio, which is calculated by dividing the volume of total proved reserves by the volume of current annual consumption. Proved reserves are an accounting concept that is based on known projects, and it is not an appropriate measure for judging total resource availability in the long term. Over time, global reserves will likely increase as new technologies increase production at existing fields and as new projects are developed.

[348] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Proved reserves include only estimated quantities of crude oil from known reservoirs, and therefore they are only a subset of the entire potential oil resource base. …

Proved reserves cannot provide an accurate assessment of the physical limits on future production but rather are intended to provide insight as to company-level or country-level development plans in the very near term. In fact, because of the particularly rigid requirements for the classification of resources as proved reserves, even the cumulative production levels from individual development projects may exceed initial estimates of proved reserves.

[349] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 25: “[Proved] Reserves are key information for assessing the net worth of an operator. Oil and gas companies traded on the U.S. stock exchange are required to report their reserves to the Securities and Exchange Commission. According to an EIA official, EIA reports a more complete measure of oil and gas reserves because it receives reports of proved reserves from both private and publically held companies.”

[350] Press release: “3 to 4.3 Billion Barrels of Technically Recoverable Oil Assessed in North Dakota and Montana’s Bakken Formation—25 Times More Than 1995 Estimate.” U.S. Department of the Interior, U.S. Geological Survey, April 10, 2008.

<www.usgs.gov>

A U.S. Geological Survey assessment, released April 10, shows a 25-fold increase in the amount of oil that can be recovered compared to the agency’s 1995 estimate of 151 million barrels of oil. …

Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.

New geologic models applied to the Bakken Formation, advances in drilling and production technologies, and recent oil discoveries have resulted in these substantially larger technically recoverable oil volumes. About 105 million barrels of oil were produced from the Bakken Formation by the end of 2007.

[351] Paper: “Percentage Depletion For Oil-A Policy Issue.” By Harrop A. Freeman. Indiana Law Journal, July 1, 1955. <www.repository.law.indiana.edu>

Page 427:

The existing proved American reserves of oil, that is, those known and commercially exploitable at current prices, equal eleven or twelve years of use at present rates, and the reserves of gas equal forty to fifty years. The Association of Petroleum Geologists reports that the areas of future prospective oil development in the United States are one hundred times those presently being exploited. The potential recoverable oil and reserves can further be enhanced by such factors as submarine oil and gas,” oil from shale and tar sands, synthesis from coal or other substitutes, and technological improvements. The situation may also be eased by importing oil, by restricting low value uses such as fuel consumption, or by realizing atomic or other new sources of power.105

[352] Calculated with data from the report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 91: “Table 4.2: Crude Oil and Natural Gas Cumulative Production and Proved Reserves, 1977-2010”

NOTE: An Excel file containing the data and calculations is available upon request.

[353] Report: “Oil and Gas Supply Module: Assumptions to the Annual Energy Outlook 2015.” U.S. Energy Information Administration, Office of Energy Statistics, September 2015. <www.eia.gov>

Pages 128–129:

Key assumptions

Domestic oil and natural gas technically recoverable resources

The outlook for domestic crude oil production is highly dependent upon the production profile of individual wells over time, the cost of drilling and operating those wells, and the revenues generated by those wells. Every year EIA re-estimates initial production (IP) rates and production decline curves, which determine estimated ultimate recovery (EUR) per well and total technically recoverable resources (TRR) [94].

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is the remaining technically recoverable resource, consisting of proved reserves [95] and unproved resources [96]. Estimates of TRR are highly uncertain, particularly in emerging plays where few wells have been drilled. Early estimates tend to vary and shift significantly over time as new geological information is gained through additional drilling, as long-term productivity is clarified for existing wells, and as the productivity of new wells increases with technology improvements and better management practices. TRR estimates used by EIA for each AEO [Annual Energy Outlook] are based on the latest available well production data and on information from other federal and state governmental agencies, industry, and academia.

Table 9.1. Technically Recoverable U.S. Crude Oil Resources as of January 1, 2013 (billion barrels)

Total Technically Recoverable Resources … Total U.S. [=] 259.8 …

Note: Crude oil resources include lease condensates but do not include natural gas plant liquids or kerogen (oil shale). Resources in areas where drilling is officially prohibited are not included in this table. The estimate of 7.3 billion barrels of crude oil resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the Mid and Southern Atlantic Outer Continental Shelf (OCS) is also excluded from the technically recoverable volumes because leasing is not expected in these areas by 2040.

NOTE: Although this EIA report does not include oil shale in its definition of crude oil, EIA sometimes includes liquid fuels produced from oil shale in its varying definitions of crude oil. For example:

Crude Oil: A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Depending upon the characteristics of the crude stream, it may also include … drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale. [Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>. Glossary (pages 211–212).]

[354] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 49:

Table 3.1: Petroleum Overview (Thousand Barrels per Day)

Field Production … Crude Oilb … Total … 2015 Average [=] 9,413

b Includes lease condensate.

CALCULATIONS:

9,413,000 barrels per day × 365 days/year = 3,435,745,000 barrels/year

259,800,000,000 technically recoverable barrels / 3,435,745,000 barrels produced in 2015 = 75.6

[355] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 49:

Table 3.1: Petroleum Overview (Thousand Barrels per Day)

Field Production … Crude Oilb … Total … 2015 Average [=] 9,413

Trade … Net Imports … 2015 Average [=] 4,738 …

NOTE: The calculation below assumes that the vast bulk of net imports are crude oil, and thus, the amounts of renewable fuel and oxygenate imports are minimal. If this were not the case, U.S. crude oil reserves would last longer than the 37.9 years determined in the calculation.

CALCULATIONS:

9,413,000 barrels of domestic crude field production per day × 365 days/year = 3,435,745,000 barrels of domestic crude field production/year

4,738,000 net imported barrels per day × 365 days/year = 1,729,370,000 net imported barrels/year

259,800,000,000 technically recoverable barrels / (3,435,745,000 barrels domestic field production + 1,729,370,000 barrels net imports) = 50.3

[356] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Table 2. Technically recoverable shale oil and shale gas unproved resources in the context of total world resources … Crude oil (billion barrels) … Total World … Total [=] 3,357 …

While the current report considers more shale formations than were assessed in the previous version, it still does not assess many prospective shale formations, such as those underlying the large oil fields located in the Middle East and the Caspian region. Further improvement in both the quality of the assessments and an increase the number of formations assessed should be possible over time. …

In addition to the key distinction between technically recoverable resources and economically recoverable resources that has been already discussed at some length, there are a number of additional factors outside of the scope of this report that must be considered in using its findings as a basis for projections of future production. In addition, several other exclusions were made for this report to simplify how the assessments were made and to keep the work to a level consistent with the available funding.

Some of the key exclusions for this report include:

Tight oil produced from low permeability sandstone and carbonate formations that can often be found adjacent to shale oil formations. Assessing those formations was beyond the scope of this report.

Coalbed methane and tight natural gas and other natural gas resources that may exist within these countries were also excluded from the assessment.

Assessed formations without a resource estimate, which resulted when data were judged to be inadequate to provide a useful estimate. Including additional shale formations would likely increase the estimated resource.

Countries outside the scope of the report, the inclusion of which would likely add to estimated resources in shale formations. It is acknowledged that potentially productive shales exist in most of the countries in the Middle East and the Caspian region, including those holding substantial nonshale oil and natural gas resources.

Offshore portions of assessed shale oil and shale gas formations were excluded, as were shale oil and shale gas formations situated entirely offshore.

[357] Calculated with data from the report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 24: “Table 3. World liquid fuels production in the Reference case, 2010-2040 (million barrels per day) … 2010 … World … Petroleum liquidsa [=] 85.1 … a Includes crude oil and lease condensate, NGPL, bitumen (oil sands), extra-heavy oil, and refinery gain.”

CALCULATION: 3,357,000,000,000 barrels / (85,100,000 barrels per day × 365 days/year) = 108

[358] Article: “DOE-Funded Project Shows Promise for Tapping Vast U.S. Oil Shale Resources.” U.S. Department of Energy, Office of Fossil Energy, March 31, 2009. <energy.gov>

“The United States holds about two thirds of the world’s estimated reserves of 3.7 trillion barrels of oil shale, an amount thought to be 40 percent larger than remaining supplies of petroleum worldwide. Scientists believe that the Green River shale formation alone, in Colorado, Utah, and Wyoming, has as much as 1.1 trillion barrels of oil equivalent.”

[359] Report: “Oil shale and nahcolite resources of the Piceance Basin, Colorado.” U.S. Department of the Interior, U.S. Geological Survey, Oil Shale Assessment Team, 2010. <pubs.usgs.gov>

Chapter 1: “An Assessment of In-Place Oil Shale Resources in the Green River Formation, Piceance Basin, Colorado.” By Ronald C. Johnson, Tracey J. Mercier, Michael E. Brownfield, Michael P. Pantea, and Jesse G. Self. <pubs.usgs.gov>

Page 5:

This assessment does not attempt to estimate the amount of oil that is economically recoverable, largely because there has not been an economic method developed to recover oil from Green River oil shale. In a recent report published by the RAND Corp. concerning the prospects for oil shale development in the United States, Bartis and others (2005, p. 5) state that: “Usually, estimates of recoverable resources are based on an analysis of the portion of the resources in place that can be economically exploited with available technology. Because oil shale production has not been profitable in the United States, such estimates do not yield useful information. Instead, calculations of recoverable resources have generally been based on rough estimates of the fraction of the resources in place that can be accessed and recovered, considering mining methods and processing losses.”

Previous estimates of the amount of oil shale that is technically recoverable without considering economics are 45 percent (Taylor, 1987) and 55 to 75 percent (Prien, 1974) of the oil in place using room-and-pillar mining methods, whereas estimates of technically recoverable resource using open-pit mining are as much as 80 percent of the oil in place (Taylor, 1987). At present, there are no estimates of the percent of the resource that could be recovered using the in-situ methods that are currently being developed, however, Taylor (1987) stressed that the amount of oil that can be recovered from any in-situ process depends on both the percent of oil that can be recovered from within the retort and the amount of oil left behind in the areas between retorts. There are currently no estimates of the percent of in-place oil that can be recovered using in-situ methods currently being developed.

[360] Report: “In-place oil shale resources examined by grade in the major basins of the Green River Formation, Colorado, Utah, and Wyoming.” By Justin E. Birdwell and others. U.S. Department of the Interior, U.S. Geological Survey, January 2013. <pubs.usgs.gov>

Page 1: “Oil shale in the Eocene Green River Formation— including the Piceance Basin of northwestern Colorado, the Uinta Basin of northeastern Utah, and the Greater Green River Basin of southwestern Wyoming—is the world’s largest known deposit of kerogen-rich rocks (Dyni, 2006).”

[361] Webpage: “About Oil Shale.” Oil Shale and Tar Sands Programmatic Environmental Impact Statement Information Center, U.S. Department of the Interior, Bureau of Land Management. Accessed March 9, 2016 at <ostseis.anl.gov>

“While oil shale is found in many places worldwide, by far the largest deposits in the world are found in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming.”

[362] Report: “In-place oil shale resources examined by grade in the major basins of the Green River Formation, Colorado, Utah, and Wyoming.” By Justin E. Birdwell and others. U.S. Department of the Interior, U.S. Geological Survey, January 2013. <pubs.usgs.gov>

Page 1:

Using a geology-based assessment methodology, the U.S. Geological Survey estimated a total of 4.285 trillion barrels of oil in-place in the oil shale of the three principal basins of the Eocene Green River Formation. Using oil shale cutoffs of potentially viable (15 gallons per ton) and high grade (25 gallons per ton), it is estimated that between 353 billion and 1.146 trillion barrels of the in-place resource have a high potential for development. …

The following overall values were determined for the entire Green River Formation: 1.146 trillion barrels (27 percent) of the total resource in the Green River Formation would be considered recoverable at a grade cutoff of 15 gallons of oil per ton of shale (GPT), and 353 billion barrels (8 percent) would be considered recoverable at a grade cutoff of 25 GPT. Oil shale with this oil-generating potential (≥25 GPT) is often described as high grade. …

… At the current rate of oil consumption in the United States, which is roughly 19 million barrels per day (U.S. Energy Information Administration, 2012b, high-grade Green River Formation oil shale resources represent a 50-year supply of oil. If the 15- to 25-GPT resource is included, then the prospective oil shale represents a 165-year supply of oil for the United States.

[363] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 49:

Table 3.1: Petroleum Overview (Thousand Barrels per Day)

Field Production … Crude Oil … Total … 2015 Average [=] 9,413

Trade … Net Imports … 2015 Average [=] 4,738 …

NOTES:

- The 2013 Interior Department report estimated that Green River Formation oil shale with “a high potential for development” would supply 150 to 165 years of U.S. oil consumption at current rates. However, the source cited in the report for U.S. “oil consumption” is actually for “refined petroleum consumption,” which includes resources that are not crude oil, such as natural gas plant liquids, renewable fuels, oxygenates, and processing gains.

- The calculation below assumes that the vast bulk of net imports are crude oil, and thus, the amounts of renewable fuel imports are minimal. If this were not the case, U.S. crude oil reserves would last longer than the 52–167 years determined in these calculations.

CALCULATIONS:

9,413,000 barrels of domestic crude field production per day × 365 days/year = 3,435,745,000 barrels of domestic crude field production/year

4,738,000 net imported barrels per day × 365 days/year = 1,729,370,000 net imported barrels/year

353,000,000,000 barrels oil shale / (3,435,745,000 domestic crude field production + 1,729,370,000 net petroleum imports) = 68.3

1,146,000,000,000 barrels oil shale / (3,435,745,000 domestic crude field production + 1,729,370,000 net petroleum imports) = 221.9

[364] Calculated with data from the report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 49:

Table 3.1: Petroleum Overview (Thousand Barrels per Day)

Field Production … Crude Oil … Total … 2015 Average [=] 9,413

NOTE: The calculation below assumes that the vast bulk of net imports are crude oil, and thus, the amounts of renewable fuel and oxygenate imports are minimal. If this were not the case, U.S. crude oil reserves would last longer than the 37.9 years determined in the calculation.

CALCULATIONS:

9,413,000 barrels of domestic crude field production per day × 365 days/year = 3,435,745,000 barrels of domestic crude field production/year

353,000,000,000 barrels oil shale / 3,435,745,000 barrels produced in 2015 = 102.7

1,146,000,000,000 barrels oil shale / 3,435,745,000 barrels produced in 2015 = 333.6

[365] Calculated with data from the report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 24: “Table 3. World liquid fuels production in the Reference case, 2010-2040 (million barrels per day) … 2010 … World … Petroleum liquidsa [=] 85.1 … a Includes crude oil and lease condensate, NGPL, bitumen (oil sands), extra-heavy oil, and refinery gain.”

CALCULATIONS:

a) 353,000,000,000 barrels oil shale / (85,100,000 barrels per day × 365 days/year) = 11.4

b) 1,146,000,000,000 barrels oil shale / (85,100,000 barrels per day × 365 days/year) = 36.9

[366] Webpage: “About Oil Shale.” Oil Shale and Tar Sands Programmatic Environmental Impact Statement Information Center, U.S. Department of the Interior, Bureau of Land Management. Accessed March 10, 2016 at <ostseis.anl.gov>

“More than 70% of the total oil shale acreage in the Green River Formation, including the richest and thickest oil shale deposits, is under federally owned and managed lands. Thus, the federal government directly controls access to the most commercially attractive portions of the oil shale resource base.”

[367] Calculated with data from:

a) Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “Table 2. Technically recoverable shale oil and shale gas unproved resources in the context of total world resources … Crude oil (billion barrels) … Total World … Total [=] 3,357”

b) Report: “In-place oil shale resources examined by grade in the major basins of the Green River Formation, Colorado, Utah, and Wyoming.” By Justin E. Birdwell and others. U.S. Department of the Interior, U.S. Geological Survey, January 2013. <pubs.usgs.gov>

Page 1: “Using a geology-based assessment methodology, the U.S. Geological Survey estimated a total of 4.285 trillion barrels of oil in-place in the oil shale of the three principal basins of the Eocene Green River Formation. Using oil shale cutoffs of potentially viable (15 gallons per ton) and high grade (25 gallons per ton), it is estimated that between 353 billion and 1.146 trillion barrels of the in-place resource have a high potential for development. … The following overall values were determined for the entire Green River Formation: 1.146 trillion barrels (27 percent) of the total resource in the Green River Formation would be considered recoverable at a grade cutoff of 15 gallons of oil per ton of shale (GPT), and 353 billion barrels (8 percent) would be considered recoverable at a grade cutoff of 25 GPT. Oil shale with this oil-generating potential (≥25 GPT) is often described as high grade.”

c) Report: “January 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 27, 2016. <www.eia.gov>

Page 49: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Production … Crude Oilb … Total … 2015 Average [=] 9,413 … Trade … Net Imports … 2015 Average [=] 4,738 … b Includes lease condensate.”

NOTE: An Excel file containing the data and calculations is available upon request.

[368] Calculated with data from:

a) Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “Table 2. Technically recoverable shale oil and shale gas unproved resources in the context of total world resources … Crude oil (billion barrels) … United States … Total [=] 223”

b) Report: “In-place oil shale resources examined by grade in the major basins of the Green River Formation, Colorado, Utah, and Wyoming.” By Justin E. Birdwell and others. U.S. Department of the Interior, U.S. Geological Survey, January 2013. <pubs.usgs.gov>

Page 1: “Using a geology-based assessment methodology, the U.S. Geological Survey estimated a total of 4.285 trillion barrels of oil in-place in the oil shale of the three principal basins of the Eocene Green River Formation. Using oil shale cutoffs of potentially viable (15 gallons per ton) and high grade (25 gallons per ton), it is estimated that between 353 billion and 1.146 trillion barrels of the in-place resource have a high potential for development. … The following overall values were determined for the entire Green River Formation: 1.146 trillion barrels (27 percent) of the total resource in the Green River Formation would be considered recoverable at a grade cutoff of 15 gallons of oil per ton of shale (GPT), and 353 billion barrels (8 percent) would be considered recoverable at a grade cutoff of 25 GPT. Oil shale with this oil-generating potential (≥25 GPT) is often described as high grade.”

c) Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 24: “Table 3. World liquid fuels production in the Reference case, 2010-2040 (million barrels per day) … 2010 … World … Petroleum liquids(a) [=] 85.1 … (a) Includes crude oil and lease condensate, NGPL, bitumen (oil sands), extra-heavy oil, and refinery gain.”

NOTE: An Excel file containing the data and calculations is available upon request.

[369] Webpage: “What is Natural Gas?” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

As a strict definition, natural gas consists of hydrocarbons that remain in the gas phase (not condensable into liquids) at 20°C and atmospheric pressure, conditions considered to be standard temperature and pressure (STP). This effectively limits the definition to components with four or fewer carbon molecules: methane (C1H4 commonly written as CH4), ethane (C2H6), propane (C3H8), and butane (C4H10). Hydrocarbons with more carbon molecules are liquid at standard conditions but may exist in gaseous phase in the reservoir. A more practical definition of natural gas includes the C5+ components that are produced with natural gas. Pentane (C5H12) begins the series that includes condensates.

NOTE: Vivek Chandra has produced a video that explains the chemistry of various natural gas compounds, along with the practical implications of this. See the section of the video from 11-19 minutes.

[370] Entry: “room temperature.” American Heritage Dictionary of the English Language. Houghton Mifflin, 2000. <www.thefreedictionary.com>

“An indoor temperature of from 20 to 25°C (68 to 77°F).”

[371] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Methane: A colorless, flammable, odorless hydrocarbon gas (CH4), which is the major component of natural gas. It is also an important source of hydrogen in various industrial processes.

Natural Gas: A gaseous mixture of hydrocarbon compounds, primarily methane, used as a fuel for electricity generation and in a variety of ways in buildings, and as raw material input and fuel for industrial processes.

Natural Gas Liquids (NGL): Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods in gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline, and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane, and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

NOTE: See the next footnote for details about the classification of natural gas liquids as petroleum.

[372] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 180: “Figure 6.2: Natural Gas Production … Volume reduction resulting from the removal of natural gas plant liquids, which are transferred to petroleum supply.”

Glossary (pages 349-370):

Petroleum: A broadly defined class of liquid hydrocarbon mixtures. Included are crude oil, lease condensate, unfinished oils, refined products obtained from the processing of crude oil, and natural gas plant liquids.

Lease Condensate: A mixture consisting primarily of pentanes and heavier hydrocarbons which is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas plant liquids, such as butane and propane, which are recovered at downstream natural gas processing plants or facilities.

Natural Gas Plant Liquids (NGPL): Those hydrocarbons in natural gas that are separated as liquids at natural gas processing plants, fractionating and cycling plants, and, in some instances, field facilities. Lease condensate is excluded. Products obtained include ethane; liquefied petroleum gases (propane, butanes, propane-butane mixtures, ethane-propane mixtures); isopentane; and other small quantities of finished products, such as motor gasoline, special naphthas, jet fuel, kerosene, and distillate fuel oil. See Natural Gas Liquids.

[373] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Natural Gas: A gaseous mixture of hydrocarbon compounds, primarily methane, used as a fuel for electricity generation and in a variety of ways in buildings, and as raw material input and fuel for industrial processes.

Hydrocarbon: An organic chemical compound of hydrogen and carbon in the gaseous, liquid, or solid phase. The molecular structure of hydrocarbon compounds varies from the simplest (methane, a constituent of natural gas) to the very heavy and very complex.

[374] Book: Energy and the Missing Resource: A View from the Laboratory. By I. Dostrovsky. Cambridge University Press, 1988.

Pages 12-13:

[Petroleum is] formed as the breakdown products of plant organisms, mainly of marine origin, that become incorporated in sediments and are then subjected to heat under high pressures over long periods of time. … [T]he precipitated organic matter must escape oxidization by oxygen dissolved in the water. Where stagnant conditions exist, accumulation of sediments rich in organic debris may be formed. Such sediments, when compacted by extensive pressure of accumulated material, become rocks, source rocks as they are called in the petroleum industry, in which oil may be formed.

Pages 21-22:

Natural gas is formed as one of the products during the alteration of organic matter contained in sediments under the influence of heat. The process was described in connection with the genesis of oil (see Section 2.1). Recall that, beyond a fairly narrow temperature region, the main product of the decomposition of organic material is methane.

[375] Book: Petroleum Chemistry and Refining. Edited by James G. Speight. Taylor and Francis, 1998. Chapter 1: “The Composition of Petroleum.” By Robert B. Long and James G. Speight. Pages 1-38.

Page 6:

Petroleum is generally accepted as being formed from buried marine sediments by the action of heat and pressure. …

Marine sediment is a term used to describe the organic biomass believed to be the raw material from which petroleum is derived, and it is mixture of many types of marine organic material that collected at the bottom of the seas and then become buried by the geological action of the earth. The types of marine organic material that collected in the sediment could be bacteria, plankton, animals, fish, and marine vegetation in varying proportions in the different sediments buried at various locations around the world. …

These buried marine deposits then undergo a series of concurrent and consecutive chemical reactions collectively called diagenesis under the influence of the temperature, pressure, and long reaction times afforded by history in the earth.

[376] Article: “Feuding Over the Origins of Fossil Fuels.” By Lisa M. Pinsker. Geotimes (published by the American Geological Institute), October 2005. <www.geotimes.org>

A petroleum geochemist at the U.S. Geological Survey, [Mike] Lewan is an expert on the origins of oil, and quite familiar with an idea that has been lingering within some scientific circles for many years now: that petroleum—oil and natural gas—comes from processes deep in Earth that do not involve organic material. This idea runs contrary to the theory that has driven modern oil exploration: that petroleum comes from the heating of organic material over time in Earth’s shallower crust.

[377] Book: Energy and the Missing Resource: A View from the Laboratory. By I. Dostrovsky. Cambridge University Press, 1988.

Page 22: “This material [methane] being a gas, is very mobile and diffuses away from its point of origin until it either escapes to the atmosphere or is trapped in a suitable formation. Because the geological structures capable of trapping oil are also effective in trapping gas, the two material are often associated.”

[378] Calculated from the dataset: “U.S. Natural Gas Flow, 2014 (Trillion Cubic Feet).” U.S. Energy Information Administration, Office of Energy Statistics, March 2015. <www.eia.gov>

“From Crude Oil Wells 5.77 … Gross Withdraws 31.88”

CALCULATION: 5.77 trillion cubic feet of gas from crude oil wells / 31.88 trillion cubic feet of gas from all wells = 18.1%

[379] Article: “Natural gas.” Encyclopædia Britannica Ultimate Reference Suite 2004.

It was in China in 211 BC that the first known well was drilled for natural gas to reported depths of 150 metres (500 feet). … The gas was burned to dry the rock salt found interbedded in the limestone. …

Natural gas was unknown in Europe until its discovery in England in 1659, and even then it did not come into wide use. Instead, gas obtained from carbonized coal (known as town gas) became the primary fuel for illuminating streets and houses throughout much of Europe from 1790 on. In North America the first commercial application of a petroleum product was the utilization of natural gas from a shallow well in Fredonia, N.Y., in 1821. The gas was distributed through a small-bore lead pipe to consumers for lighting and cooking.

[380] Article: “Natural gas.” Encyclopædia Britannica Ultimate Reference Suite 2004.

Throughout the 19th century the use of natural gas remained localized because there was no way to transport large quantities of gas over long distances. Natural gas remained on the sidelines of industrial development, which was based primarily on coal and oil. An important breakthrough in gas-transportation technology occurred in 1890 with the invention of leakproof pipeline coupling. Nonetheless, materials and construction techniques remained so cumbersome that gas could not be used more than 160 kilometres (100 miles) from a source of supply. Thus, associated gas was mostly flared (i.e., burned at the wellhead), and nonassociated gas was left in the ground, while town gas was manufactured for use in the cities.

Long-distance gas transmission became practical during the late 1920s because of further advances in pipeline technology. From 1927 to 1931 more than 10 major transmission systems were constructed in the United States. Each of these systems was equipped with pipes having diameters of approximately 51 centimetres (20 inches) and extended more than 320 kilometres. Following World War II, a large number of even longer pipelines of increasing diameter were constructed. The fabrication of pipes having a diameter of up to 142 centimetres became possible.

[381] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 139: “Natural gas presents different transportation requirement problems. Before World War II, its use was limited by the difficulty of transporting it over long distances. The gas found in oil fields was frequently burned off; and unassociated (dry) gas was usually abandoned. After the war, new steel alloys permitted the laying of large-diameter pipes for gas transport in the United States.”

[382] Webpage: “Gas Pipelines.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

Pipelines are the most common, and usually the most economic, delivery system to transport gas from the field to the consumer. Pipelines are a fixed, long-term investment that can be uneconomic for smaller and more remote gas fields. …

The volume of gas that can be transported in a pipeline depends on two main factors: the pipeline operating pressure and pipe diameter. The maximum diameter of pipelines continues to increase every few years. As diameters of 48 in. (121 cm) become common, the industry may be approaching the practical limit to onshore pipelines. To handle the increasing demand, it is likely that operating pressures will increase rather than the size of the pipe. …

Increasing pressure requires larger and thicker pipes, larger compressors, and higher safety standards, all of which substantially increase the capital and operating expenses of a system.

[383] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 139:

Natural gas is also transported by seagoing vessels. The gas is either transported under pressure at ambient temperatures (e.g., propane and butanes) or at atmospheric pressure, but with the cargo under refrigeration (e.g., liquefied petroleum gas). …

Natural gas is much more expensive to ship than crude oil because of its lower density. Most natural gas moves by pipeline, but in the late 1960s, tanker shipments of natural gas (LNG) began, particularly from the producing nations in the Pacific to Japan. Special alloys are required to prevent the tanks from becoming brittle at the low temperatures (-161ºC, -258ºF) required to keep the gas liquid.

[384] Calculated with data from:

a) Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 322: “Table A2. Approximate Heat Content of Petroleum Production, Imports, and Exports, Selected Years, 1949-2011 (Million Btu per Barrel) … Production … Crude Oil … 2011 [=] … 5.800”

b) Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 324: “Table A4. Approximate Heat Content of Natural Gas, Selected Years, 1949-2011 (Btu per Cubic Foot†) … Production … Marketed … 2011 [=] 1,097”

c) Webpage: “International Energy Statistics – Units.” U.S. Energy Information Administration. Accessed September 3, 2013 at <www.eia.gov>

“Volume Equivalent Conversions … [One] Barrel [=] 5.61460 Cubic Feet”

†NOTE: A cubic foot of natural gas is the “amount of natural gas contained at standard temperature and pressure (60 degrees Fahrenheit and 14.73 pounds standard per square inch) in a cube whose edges are one foot long.” [Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>. Glossary (pages 349-370): “Cubic Foot (Natural Gas).”]

CALCULATION: (5,800,000 Btu per barrel of crude / 5.6146 cubic feet per barrel) / 1,097 Btu per cubic foot of natural gas) = 942

[385] Webpage: “Gas Pricing.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

[T]o transport … methane … requires either a pipeline, or expensive compression or liquefaction transformation….

[B]ecause natural gas is difficult to transport, natural gas prices tend to be set locally or regionally. The large majority (over 90%) of traded natural gas is transported by pipeline.

[386] Webpage: “Liquefied Natural Gas Chain.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

Though the overall percentage of gas transported as LNG [liquefied natural gas] is less than 10% of global gas trade, it is growing rapidly, involving an increasing number of buyers and sellers. …

LNG is simply an alternative method to transport methane from the producer to the consumer. Methane (CH4) gas is cooled to minus 160°C (or more accurately, –161.5°C (–260°F), converting its gaseous phase into an easily transportable liquid whose volume is approximately 600 times less than the equivalent volume of methane gas. (The exact shrinkage is closer to 610 times, but 600 is commonly quoted.) …

Gas converted to LNG can be transported by ship over long distances where pipelines are neither economic nor feasible. At the receiving location, liquid methane is offloaded from the ship and heated, allowing its physical phase to return from liquid to gas. This gas is then transported to gas consumers by pipeline in the same manner as natural gas produced from a local gas field. …

Liquefaction plants are typically the most expensive element in an LNG project. Because 8%–10% of gas delivered to the plant is used to fuel the refrigeration process, overall operating costs are high even though other costs, such as labour and maintenance, are low.

[387] Article: “Natural gas.” Encyclopædia Britannica Ultimate Reference Suite 2004.

Throughout the 19th century the use of natural gas remained localized because there was no way to transport large quantities of gas over long distances. Natural gas remained on the sidelines of industrial development, which was based primarily on coal and oil. An important breakthrough in gas-transportation technology occurred in 1890 with the invention of leakproof pipeline coupling. Nonetheless, materials and construction techniques remained so cumbersome that gas could not be used more than 160 kilometres (100 miles) from a source of supply. Thus, associated gas was mostly flared (i.e., burned at the wellhead), and nonassociated gas was left in the ground, while town gas was manufactured for use in the cities.

[388] Book: The Chemistry and Technology of Petroleum (Fourth Edition). By James G. Speight. CRC Press, 2007.

Page 139: “Natural gas presents different transportation requirement problems. Before World War II, its use was limited by the difficulty of transporting it over long distances. The gas found in oil fields was frequently burned off; and unassociated (dry) gas was usually abandoned. After the war, new steel alloys permitted the laying of large-diameter pipes for gas transport in the United States.”

[389] Calculated with data from the report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 181: “Table 6.2: Natural Gas Production, Selected Years, 1949-2011 (Billion Cubic Feet)”

NOTE: An Excel file containing the data and calculations is available upon request.

[390] Calculated from the dataset: “U.S. Natural Gas Flow, 2014 (Trillion Cubic Feet).” U.S. Energy Information Administration, Office of Energy Statistics, March 2015. <www.eia.gov>

“Vented and Flared [=] 0.28 … Marketed Production [=] 27.28”

CALCULATION: 0.28 trillion cubic feet of vented and flared gas / 27.28 trillion cubic feet of marketed production gas = 1.0%

NOTE: Instead of calculating venting and flaring as a percentage of natural gas extraction (as in the previous footnote), marketed production is used as the denominator. This is done to provide an accurate comparator for the worldwide production data, because worldwide extraction data is not available.

[391] Calculated with data from:

a) Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 50: “Table 7. World natural gas production by region and country in the Reference case, 2010-2040 (trillion cubic feet) … Total world … 2010 [=] 111.1”

b) Webpage: “Estimated Flared Volumes from Satellite Data, 2007-2011.” World Bank. Last updated June 14, 2012. <web.worldbank.org>

“Volumes in bcm [billions of cubic meters] … Global flaring level … 2010 [=] 138”

c) Webpage: “International Energy Statistics – Units.” U.S. Energy Information Administration. Accessed September 3, 2013 at <www.eia.gov>

“Volume Equivalent Conversions … [One] Cubic Meter [=] 35.31478 Cubic Feet”

CALCULATION: 138,000,000,000 cubic meters flared gas / (111,100,000,000,000 cubic feet production / 35.31478 cubic feet per cubic meter) = 4.4%

[392] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

More than 97% of the world’s synthetic fertilizer is produced from synthetically produced ammonia derived from natural gas. The process requires relatively high temperatures and pressures, and thus requires cheap energy to be economic. Natural gas, with its relatively cheap price, provides both the energy and the feedstock for the process. …

Today, most large cities in North America, Europe, and Northern Asia have extensive natural gas networks supplying residential and commercial consumers with clean and reliable natural gas, primarily for space heating, water heating, and cooking. Many cities in developing countries are also installing local gas pipelines and networks.

[393] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 17: “[G]as gives you a lot of energy for very little money. That is why it is almost always preferable to cook and heat your home with gas, if it is available.”

Page 25: “Gas is used in power plants to generate electricity, and in factories both as a fuel and as an ingredient for a variety of chemicals.”

[394] Webpage: “Gas Pricing.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

“NGLs are desired by global markets to produce various petrochemical products, to be blended with crude oil to make more valuable products, and can also be combusted directly.”

[395] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 49:

The uses of NGL [natural gas liquids] are diverse. The lightest NGL component, ethane, is used almost exclusively as a petrochemical feedstock to produce ethylene, which in turn is a basic building block for plastics, packaging materials, and other consumer products. … Propane is the most versatile NGL component, with applications ranging from residential heating, to transportation fuel for forklifts, to petrochemical feedstock for propylene and ethylene production (nearly one-half of all propane use in the United States is as petrochemical feedstock). Butanes are produced in much smaller quantities and are used mostly in refining (for gasoline blending or alkylation) or as chemical feedstock. The heaviest liquids, known as pentanes plus, are used as ethanol denaturant, blendstock for gasoline, chemical feedstock, and, more recently, as diluent for the extraction and pipeline movement of heavy crude oils from Canada.

[396] Webpage: “What are natural gas liquids and how are they used?” U.S. Energy Information Administration, April 20, 2012. <www.eia.gov>

NGL Attribute Summary Ethane … Ethane … End Use Products … Plastic bags; plastics; anti-freeze, detergent …

… There are many uses for NGLs, spanning nearly all sectors of the economy. NGLs are used as inputs for petrochemical plants, burned for space heat and cooking, and blended into vehicle fuel. …

Ethane occupies the largest share of NGL field production. It is used almost exclusively to produce ethylene, which is then turned into plastics. Much of the propane, by contrast, is burned for heating, although a substantial amount is used as petrochemical feedstock. A blend of propane and butane, sometimes referred to as “autogas,” is a popular fuel in some parts of Europe, Turkey, and Australia. Natural gasoline (pentanes plus) can be blended into various kinds of fuel for combustion engines, and is useful in energy recovery from wells and oil sands.

[397] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Natural Gas2 [=] 28% … Transportation [=] 3% … Industrial5 [=] 44% … Residential and Commercial6 [=] 76%6 … Electric Power7 [=] 26% …

2 Excludes supplemental gaseous fuels. …

5 Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants.

6 Includes commercial combined-heat-and-power (CHP) and commercial electricity-only plants.

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. Includes 0.2 quadrillion Btu of electricity net imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[398] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 83: “Table 4.1: Natural Gas Overview (Billion Cubic Feet)”

NOTE: An Excel file containing the data and calculations is available upon request.

[399] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 83: “Table 4.1: Natural Gas Overview (Billion Cubic Feet)”

NOTE: An Excel file containing the data and calculations is available upon request.

[400] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1:

For decades, the United States has relied on imports of oil and natural gas to meet domestic needs. As recently as 2007, the expectation was that the nation would increasingly rely on imports of natural gas to meet its growing demand. However, recent improvements in technology have allowed companies that develop petroleum resources to extract oil and natural gas from shale formations,1 known as “shale oil” and “shale gas,” respectively, which were previously inaccessible because traditional techniques did not yield sufficient amounts for economically viable production.

[401] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 4: “In the United States, one of the keys to increasing natural gas production has been advances in the application of horizontal drilling and hydraulic fracturing technologies, which made it possible to develop the country’s vast shale gas resources and contributed to a near doubling of total U.S. technically recoverable natural gas resource estimates over the past decade.”

[402] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 34: “A strong rebound in gas and then oil production in the United States over the past few years has taken markets and policymakers by surprise…. The surge in production is largely the result of the new ability of producers to extract oil and gas from unconventional geological formations—so-called shale rock and tight rock or sand formations.”

[403] Webpage: “Factors Affecting Natural Gas Prices.” U.S. Energy Information Administration. Last updated April 23, 2013. <www.eia.gov>

Natural gas prices are a function of market supply and demand. Because of limited alternatives for natural gas consumption or production in the short run, even small changes in supply or demand over a short period can result in large price movements to bring supply and demand back into balance. …

Increases in supply result in lower prices, and decreases in supply tend to increase prices. …

U.S. dry production increased from 2006 through 2012, when it reached its highest recorded annual total. The increases in production were the result of more efficient, cost-effective drilling techniques, notably in the production of natural gas from shale formations. Increased natural gas supply tends to dampen prices. In turn, lower prices can erode incentive for drilling, which eventually results in decreased production. …

Hurricanes and other severe weather can affect the supply of natural gas. For example, in the summer of 2005, hurricanes along the U.S. Gulf Coast caused the equivalent of about 4% of U.S. total production to be shut in between August 2005 and June 2006. …

The strength of the economy is a major factor influencing natural gas markets. During periods of economic growth, the increased demand for goods and services from the commercial and industrial sectors generates an increase in natural gas demand. This is particularly true in the industrial sector, which is the leading consumer of natural gas, as both a plant fuel and as a feedstock for many products such as fertilizer and pharmaceuticals. The increased demand can lead to increased production, and, in general, higher prices. Declining or weak economic growth tends to have the opposite effect. …

During cold months, residential and commercial end users consume natural gas for heating, which places upward pressure on prices as demand increases. If unexpected or severe weather occurs, the effect on prices intensifies because supply is often unable to react quickly to short-term increases in demand. These effects of weather on natural gas prices may be exacerbated if the natural gas transportation system is already operating at full capacity. Under these conditions, prices tend to increase, which reduces overall demand for natural gas and brings the market into balance. Natural gas supplies that were placed in storage during periods of lesser demand may be used to cushion the impact of high demand during cold weather. …

Temperatures also can have an effect on prices in the cooling season. About 30% of U.S. electricity is generated by natural gas. Hotter than normal temperatures can increase the demand for air conditioning, in turn, increasing the power sector’s demand for natural gas, which can increase prices.

[404] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Pages 31-32: “The growth in production of shale gas has increased the overall supply of natural gas in the U.S. energy market. Since 2007, increased shale gas production has contributed to lower prices for consumers, according to EIA and others.”

[405] Article: “U.S. Gas Fields Go From Bust to Boom.” By Ben Casselman. Wall Street Journal, April 30, 2009. <online.wsj.com>

But new technologies and a drilling boom have helped production rise 11% in the past two years. Now there’s a glut, which has driven prices down to a six-year low and prompted producers to temporarily cut back drilling and search for new demand. …

The weakening economy eroded demand for both oil and gas. Natural gas, unlike oil, suffered from a supply glut. U.S. gas production rose 7.2% last year…. Natural-gas prices have fallen 41% to their lowest since 2002.

[406] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 45:

Historically, the regulation of U.S. natural gas prices was based on the cost of providing the natural gas (i.e., cost of service). Pipeline companies bought gas from producers at a regulated wellhead price, stored their gas and shipped it via their own facilities, and then sold it after transport, bundling the cost of the gas with its shipping and storage costs into a single price. By 1993, the U.S. natural gas industry had largely been deregulated. Wellhead prices were no longer set by the government, and pipeline companies could no longer bundle services but were required to offer transportation and storage services to third parties on a nondiscriminatory basis. Natural gas trade flourished, and multiple pricing points developed across the United States and Canada, the most active and publicized of which is the Henry Hub in Louisiana.

Until 2005, even with no direct linkage between oil prices and natural gas prices, the two tended to move together, with the market prices for oil (in dollars per barrel) and natural gas (in dollars per million Btu) maintaining a relatively stable ratio of around 7:1, with natural gas priced at a slight discount relative to the oil price on a Btu basis.23 However, as oil prices climbed from an average of $56 per barrel in 2005 to an average of $100 per barrel in 2008, the discount for natural gas relative to oil also grew, from the 7:1 ratio in 2005 to 11:1 in 2008. After 2008, the natural gas discount relative to oil widened further, as oil prices remained relatively high while growing U.S. shale gas production helped to weaken natural gas prices. The oil-to-gas price ratio grew to an average of more than 35:1 in 2012, with a Btu of crude oil selling for more than five times the price for a Btu of natural gas.

23 The ratio is calculated as the crude oil price in dollars per barrel divided by the natural gas price in dollars per million Btu. A ratio of around 6:1 indicates price parity between crude oil and natural gas on a Btu basis. A ratio above 6:1 indicates that the natural gas price is at a discount relative to the oil price on a Btu basis.

[407] Webpage: “Gas Pricing.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed March 11, 2016 at <natgas.info>

A large majority of crude oil is bought and sold directly or indirectly through highly liquid global markets. …

In contrast, because natural gas is difficult to transport, natural gas prices tend to be set locally or regionally. …

The graphic below divides the world gas markets into four groupings …

In the future, natural gas pricing around the world will continue to be divergent and unlinked between markets. As the LNG [liquefied natural gas] industry grows and links more and more markets, there may be some convergence at the margins – however, since a large majority of gas will continue to be transported by pipeline, the overall impact of this will be limited.

[408] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

EIA is often asked about the implications of abundant shale resources for natural gas and oil prices. Because markets for natural gas are much less globally integrated than world oil markets, the rapid growth in shale gas production since 2006 has significantly lowered natural gas prices in the United States and Canada compared to prices elsewhere and to prices that would likely have prevailed absent the shale boom.

[409] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Pages 48-49: “[G]rowing natural gas production … has led to logistical problems in some areas. For example, much of the increased ethane supply in the Marcellus region is stranded because of the distance from petrochemical markets in the Gulf Coast area.”

[410] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35: “Oil markets are sufficiently integrated that prices adjust based on global demand and supply.”

[411] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fpc.state.gov>

“Global developments may be difficult to understand from the U.S. perspective, where oil production is rising, demand growth remains weak, and no oil is imported from Iran. However, the market for oil is globally integrated; events anywhere can affect oil prices.”

[412] Dataset: “Natural Gas Prices (Dollars per Thousand Cubic Feet).” U.S. Energy Information Administration, June 30, 2016. <www.eia.gov>

NOTE: After 2011, EIA stopped publishing the natural gas wellhead price, which provided the only national average production price of natural gas. However, according to EIA, the import price is “a pretty good predictive variable” for the wellhead price.† Hence, Just Facts is using this to approximate the production price. [† Email from the U.S. Energy Information Administration to Just Facts, July 8, 2016.]

[413] Calculated with data from:

a) Dataset: “Natural Gas Prices (Dollars per Thousand Cubic Feet).” U.S. Energy Information Administration, June 30, 2016. <www.eia.gov>

b) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

“Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U. S. city average, all items (1982-84=100, unless otherwise noted)”

NOTES:

- An Excel file containing the data and calculations is available upon request.

- After 2011, EIA stopped publishing the natural gas wellhead price, which provided the only national average production price of natural gas. However, according to EIA, the import price is “a pretty good predictive variable” for the wellhead price.† Hence, Just Facts graphed all available years of the wellhead price and import price to convey the general price trends over time. [† Email from the U.S. Energy Information Administration to Just Facts, July 8, 2016.]

[414] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Natural Gas Wellhead Price: Price of natural gas calculated by dividing the total reported value at the wellhead by the total quantity produced as reported by the appropriate agencies of individual producing States and the U.S. Mineral Management Service. The price includes all costs prior to shipment from the lease, including gathering and compression costs, in addition to State production, severance, and similar charges.

[415] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Natural Gas2 [=] 28% … Transportation [=] 3% … Industrial5 [=] 44% … Residential and Commercial6 [=] 76%6 … Electric Power7 [=] 26% …

2 Excludes supplemental gaseous fuels. …

5 Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants.

6 Includes commercial combined-heat-and-power (CHP) and commercial electricity-only plants.

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. Includes 0.2 quadrillion Btu of electricity net imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[416] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 27:

In an electrical generator electricity is made by turning a magnet in a magnetic field. The changing magnetic field drives the electrical current. With the exception of solar cells and fuel cells (which are discussed in chapters 4 and 6), all ways of generating electricity in some way drive a generator of this type. For example, fossil fuels are used to heat water into steam, which can be used to power a steam turbine. The steam turbine then drives the electrical generator.

A gas turbine works in a similar way: when the gas is ignited and starts to burn, it expands. The expanding gas is used to power an electrical generator through a turbine. In addition, the heat of the burning gas is then used to make steam, which powers a steam turbine.

This process is called combined cycle, and it has a high efficiency. If the waste heat of the steam turbine is also used, for example by a factory or for household heating, we have a Cogeneration Plant or Combined Heat and Power Plant.

[417] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

A typical coal-fired electrical plant might be 38% efficient, so a little more than one-third of the chemical energy content of the fuel is ultimately converted to usable electricity. …

In natural gas combined cycle, or NGCC, power plants, we now have technology that takes the waste heat from a natural gas turbine and uses it to power a steam turbine, resulting in a power plant that is as much as 60% efficient.5 Similar technologies are being developed for use in coal power plants.

[418] Calculated with data from the report: “June 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 27, 2016. <www.eia.gov>

Page 110: “Table 7.2b: Electricity Net Generation: Electric Power Sector”

NOTE: An Excel file containing the data and calculations is available upon request.

[419] Calculated with data from the report: “Electric Power Monthly with Data for January 2016.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2016. <www.eia.gov>

Page 15 (in PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

NOTE: An Excel file containing the data and calculations is available upon request.

[420] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26:

Electricity peak loads in Kansas are the greatest during the summer months, primarily due to the electricity needs of air-conditioning systems. …

In order to cost-effectively meet the varying demand of their customers at different times of the year and even different times of the day, most utilities maintain a diverse portfolio of electric power plants (e.g., generating units) that use a variety of fuels. These generating units can be distinguished according to the type of power they produce (firm vs. intermittent) as well as the type of load they are designed to meet (base, peak, or intermediate).

[421] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“Electric power systems must match generation and load in real time, with tight tolerances. As a result, both system stress and prices can vary considerably throughout the day. … Load curve shapes vary among regions and change with the season of the year.”

[422] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 1:

“Whole-building electric load” is the total electrical power used by a building at a given moment. The load changes with time in response to changes in lighting levels; heating, ventilating, and air conditioning (HVAC) requirements; and uses such as computers, copy machines, and so on. The curve that represents load as a function of time, called the “load shape,” can often yield useful information. Unexpectedly high night-time loads may indicate waste (such as lights that needlessly remain on when the building is unoccupied); a change in load shape may indicate an equipment or thermostat malfunction; unexpectedly high sensitivity to outdoor temperature may indicate that excessive outdoor air is being brought into the building by the HVAC system; and so on.

[423] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26: “Electricity consumption (also called ‘load’) is divided into three categories: base, peak, and intermediate load. Base load refers to demand that occurs continuously, day and night, seven days a week. Peak load, on the other hand, refers to maximum demand that occurs within a given period of time. Intermediate load is a more generic term applied to demand that occurs between base and peak load.”

[424] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Peak load: The maximum load during a specified period of time.

Base load: The minimum amount of electric power delivered or required over a given period of time at a steady rate.

Base load capacity: The generating equipment normally operated to serve loads on an around-the-clock basis.

Base load plant: A plant, usually housing high-efficiency steam-electric units, which is normally operated to take all or part of the minimum load of a system, and which consequently produces electricity at an essentially constant rate and runs continuously. These units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs.

[425] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 22: “Figure 15: Sketch indicating five parameters that we recommend as a minimum set to characterize load shape. The value of each parameter can be calculated for each day; these values can then be summarized (e.g. average peak load, standard deviation of peak load).”

[426] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

“The development of IPPs [Independent Power Producers] and the increased efficiency of gas-fired combined cycle plants have allowed gas to become the fuel of choice in both intermediate and peak load phases.”

[427] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 44: “In general, [natural gas] combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.”

[428] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Even though natural gas prices have increased significantly in recent years, natural gas remains the dominant source of peak capacity because power plants using that fuel are less expensive to build than coal-fired plants or nuclear reactors and easier to start up and shut down.”

[429] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“The transition from relatively lower loads to higher loads in the morning is called the ‘morning ramp’. This transition can stress power systems and lead to volatile prices. … Responding to such load changes often requires using units that can start up quickly. These units can be more expensive to operate than units that stay on for long periods such as baseload units. Power prices can increase during ramping, sometimes considerably, for short periods.”

[430] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Historically, most base-load capacity has been provided using coal or nuclear technologies because, once the plants have been built, low fuel costs make them relatively cheap to operate continuously.”

Page 4: “Pulverized coal power plants, which burn solid coal ignited by injected air, are by far the most common option for generating base-load electricity.”

[431] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 27:

Power plants that are used to meet the minimum or “base load” of the system are referred to as base-load generating units; they are run continuously and operated, in general, so as to produce electricity at a constant rate. Base-load units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs. Costs are minimized by operating units with the lowest fuel costs for the most hours in the year (i.e., at a high capacity factor). Generally, base-load units include nuclear, coal-fired, geothermal, hydropower, and waste-to-energy plants.63

[432] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

Coal remains the dominant fuel for the world’s thermal electric power plants. Coal has been the main thermal electric fuel due to its cheap price, worldwide availability, easy transport, and low-technology threshold. However, as stated above, Coal’s biggest drawback is the pollution emitted from its combustion. …

Typically, base load power stations are large nuclear, hydroelectric, or coal-burning plants that are expensive to build, with high fixed costs. However, they are cheap to maintain and operate. They operate continuously and are difficult to switch on or off.

[433] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

“In 2009, coal began losing its price advantage over natural gas for electricity generation in some parts of the country, particularly in the eastern United States as a surge in natural gas production from domestic shale deposits (made possible by advances in drilling technologies) substantially reduced the price of natural gas.”

[434] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36: “The main increased usage of gas has occurred in the U.S. power sector, where the share of electricity produced with natural gas has started to rise because many power plants can switch between gas and the now relatively more expensive (and dirtier) coal.”

[435] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee/Northwest Natural Gas Association Planning Task Force, August 2012. <www.ferc.gov>

Page 3:

In the United States, over the past decade, the single largest sector of natural gas demand growth has occurred in the area of power generation. As emissions from coal-fired power plants have come under increasing public scrutiny, more and more electric utilities and merchant power producers have turned to natural gas for new baseload and peaking generation. This trend has been accelerated in recent years, due to the boom of shale gas production, the relatively short lead time and low cost of natural gas-fired power plant construction, and the robust flexibility that natural gas-fired plants can bring to the area of Variable Energy Resource (VER) integration (i.e., wind and solar).

[436] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 39:

Over the past 20 years, natural gas has been the go-to fuel for new electricity generation capacity. From 1990 to 2011, natural gas-fired plants accounted for 77 percent of all generating capacity additions, and many of the plants added were very efficient combined-cycle plants. However, with slow growth in electricity demand and spikes in natural gas prices between 2005 and 2008, much of the added capacity was used infrequently. Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally. …

At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated. …

In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:

• A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently

• Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas

• Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices

• Rising coal prices.

Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.

Page 41:

Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. … The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements. …

For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity (82). New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely. …

… Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.

[437] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 3:

Although coal is expected to continue its important role in U.S. electricity generation, there are many uncertainties that could affect future outcomes. Chief among them are the relationship between coal and natural gas prices and the potential for policies aimed at reducing greenhouse gas (GHG) emissions. In 2012, natural gas prices were low enough for a few months for power companies to run natural gas-fired generation plants more economically than coal plants in many areas. During those months, coal and natural gas were nearly tied in providing the largest share of total electricity generation, something that had never happened before.

Page 40:

The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC [natural gas combined cycle] units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. … Because fuel prices vary by region, and because there is also considerable variation in efficiencies across the existing fleet of both coal-fired and combined-cycle plants, dispatch-level competition between coal and natural gas continues.

Page 43: “The delivered cost of coal in the [southeastern United States] region is somewhat higher than in many other regions. Central Appalachian and Illinois Basin coals must be transported by rail or barge to the Southeast, and coal from the Powder River Basin must travel great distances by rail. The region also uses some imported coal, typically along the Gulf Coast, which tends to be more expensive.”

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely.

NOTE: Price variations in coal and natural gas are shown in the above graph of fossil fuel costs of electric power plants.

[438] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 27:

In an electrical generator electricity is made by turning a magnet in a magnetic field. The changing magnetic field drives the electrical current. With the exception of solar cells and fuel cells (which are discussed in chapters 4 and 6), all ways of generating electricity in some way drive a generator of this type. For example, fossil fuels are used to heat water into steam, which can be used to power a steam turbine. The steam turbine then drives the electrical generator.

A gas turbine works in a similar way: when the gas is ignited and starts to burn, it expands. The expanding gas is used to power an electrical generator through a turbine. In addition, the heat of the burning gas is then used to make steam, which powers a steam turbine.

This process is called combined cycle, and it has a high efficiency. If the waste heat of the steam turbine is also used, for example by a factory or for household heating, we have a Cogeneration Plant or Combined Heat and Power Plant.

[439] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 40:

The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC [natural gas combined cycle] units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. When the ratio of natural gas prices to coal prices is approximately 1.5 or lower, a typical natural gas-fired combined-cycle plant has lower generating costs than a typical coal-fired plant.

[440] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

A typical coal-fired electrical plant might be 38% efficient, so a little more than one-third of the chemical energy content of the fuel is ultimately converted to usable electricity. …

In natural gas combined cycle, or NGCC, power plants, we now have technology that takes the waste heat from a natural gas turbine and uses it to power a steam turbine, resulting in a power plant that is as much as 60% efficient.5 Similar technologies are being developed for use in coal power plants.

[441] Calculated with data from the report: “April 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, April 26, 2016. <www.eia.gov>

Page 143: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”

NOTE: An Excel file containing the data and calculations is available upon request.

[442] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Natural Gas2 … Transportation [=] 3% …

2 Excludes supplemental gaseous fuels. …

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[443] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Pages 31-32:

The growth in production of shale gas has increased the overall supply of natural gas in the U.S. energy market. Since 2007, increased shale gas production has contributed to lower prices for consumers…. These lower prices create incentives for wider use of natural gas in other industries. For example, several reports by government, industry, and others have observed that if natural gas prices remain low, natural gas is more likely to be used to power cars and trucks in the future.

[444] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36:

But in the longer term, there is potential for other industries to switch to natural gas—even transportation, because natural gas can be used in internal combustion engines, which now rely mainly on refined petroleum products such as gasoline or diesel fuel. …

If there is widespread substitution of natural gas for petroleum products, global oil markets would be affected. The price incentives are there. On an energy-equivalent basis, natural gas prices are a fraction of gasoline or diesel prices in the United States. The price incentives are reinforced by the prospective abundance of natural gas.

[445] Article: “U.S. Gas Fields Go From Bust to Boom.” By Ben Casselman. Wall Street Journal, April 30, 2009. <online.wsj.com>

Mr. [T. Boone] Pickens has spent millions promoting an energy plan that aims to, among other things, convert thousands of big-rig trucks to run on natural gas. Mr. Pickens has large investments in natural gas and stands to benefit if his plan is adopted. In TV ads, Internet videos and speeches, he emphasizes a different goal: reducing U.S. dependence on foreign oil. …

Some environmentalists have embraced Mr. Pickens’s plan as a way to fight climate change. Carl Pope, executive director of the Sierra Club, says he sees natural gas as a “bridge fuel” that could help the U.S. burn less coal and oil until renewable sources of energy are ready to take over. …

Some environmental groups, including the Natural Resources Defense Council, have argued that natural gas is better used to replace coal for power generation, and that cars should run on electricity generated by the sun, wind and natural gas.

[446] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

“Studies indicate that vehicles operating on natural gas versus conventional fuels such as gasoline and diesel fuels can reduce CO output by 90% to 97% and CO2 by 25%. The switch can also significantly reduce NOx emissions, as well as nonhydrocarbon emissions and particulates.”

[447] Article: “Oil Prices: What’s Behind the Drop? Simple Economics.” By Clifford Krauss. New York Times, March 8, 2016. <www.nytimes.com>

The oil industry, with its history of booms and busts, is in its deepest downturn since the 1990s, if not earlier. …

The cause is the plunging price of a barrel of oil, which has fallen more than 70 percent since June 2014.

Prices recovered a few times last year, but the cost of a barrel of oil has already sunk this year to levels not seen since 2003 as an oil glut has taken hold.

[448] Article: “Honda Civic Hybrid, Natural-Gas Models Eliminated After 2015.” By John Voelcker. Green Car Reports, June 16, 2015. <www.greencarreports.com>

… [T]wo members of today’s Civic lineup won’t survive into the new generation: the Honda Civic Hybrid, and the Honda Civic Natural Gas.

Honda executive vice-president John Mendel revealed that both models would be discontinued in a business update briefing for media yesterday. …

He … said Honda will cancel the Civic Natural Gas model (nee Civic GL).

The elimination is due to a combination of low gasoline prices—which have eliminated the price advantage of natural gas in many markets—and a lack of interest on the part of consumers.

[449] Article: “Honda to Discontinue CNG and Hybrid Civic Models.” By Mike Ramsey. Wall Street Journal, June 15, 2015. <www.wsj.com>

Mr. Mendel [executive vice president of American Honda] said the company has sold about 16,000 Civic CNG models since 1998. “We tried and tried and tried, but we just didn’t see the uptake,” he said.

The recent decline in gasoline prices has reduced the price advantage of natural gas. Plus, he said, the scarcity of refueling stations became too much of a sales hurdle.

[450] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

Though the benefits of natural gas as a transport fuel are well-known, growth in direct natural gas usage in the transportation sector has been slow to materialize. …

Fuel supply infrastructure around the world heavily favors reliance on traditional liquid fuels, making conversion to natural gas difficult.

[451] Article: “U.S. Gas Fields Go From Bust to Boom.” By Ben Casselman. Wall Street Journal, April 30, 2009. <online.wsj.com>

“Energy Secretary Steven Chu and some other policy makers have expressed doubts about the practicality of retrofitting hundreds of thousands of service stations to offer natural gas.”

[452] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36: “A switch to greater use of natural gas typically involves investment, which is attractive only if natural gas prices remain relatively lower over the life of a project.”

[453] Review: “2012 Honda Civic Natural Gas.” By Michael Austin. Car and Driver, March 2012. <www.caranddriver.com>

“[T]here are large sections of Michigan without any CNG filling stations, a pattern echoed throughout the country (click here for a map). That means the Civic CNG, from a practical standpoint, can only be operated on a 200-mile tether from your local filling station (or your own pump, if you’re a fleet owner) unless you live in CNG-heavy areas such as the Eastern Seaboard or California.”

[454] Report: “A Primer on Alternative Transportation Fuels.” By Timothy Coffey. National Defense University, Center for Technology and National Security Policy, September 2010. <ctnsp.dodlive.mil>

Page 25:

Table 6. Energy content and chemical composition of several energy sources referenced to gasoline. The bracket < > indicates the average chemical formula. (Source: modified from Coffey et al.7)

Energy Per Unit Volume

[455] Webpage: “Few transportation fuels surpass the energy densities of gasoline and diesel.” U.S. Energy Information Administration, February 14, 2013. <www.eia.gov>

Energy density and the cost, weight, and size of onboard energy storage are important characteristics of fuels for transportation. Fuels that require large, heavy, or expensive storage can reduce the space available to convey people and freight, weigh down a vehicle (making it operate less efficiently), or make it too costly to operate, even after taking account of cheaper fuels. Compared to gasoline and diesel, other options may have more energy per unit weight, but none have more energy per unit volume.

On an equivalent energy basis, motor gasoline (which contains up to 10% ethanol) was estimated to account for 99% of light-duty vehicle fuel consumption in 2012. Over half of the remaining 1% was from diesel; all other fuels combined for less than half of 1%. The widespread use of these fuels is largely explained by their energy density and ease of onboard storage, as no other fuels provide more energy within a given unit of volume.

The chart above compares energy densities (both per unit volume and per unit weight) for several transportation fuels that are available throughout the United States. The data points represent the energy content per unit volume or weight of the fuels themselves, not including the storage tanks or other equipment that the fuels require. For instance, compressed fuels require heavy storage tanks, while cooled fuels require equipment to maintain low temperatures.

[456] Webpage: “Civic Natural Gas – Frequently Asked Questions.” American Honda Motor Company. Accessed September 4, 2013 at <automobiles.honda.com>

“In fact, the Civic Natural Gas is the cleanest internal-combustion vehicle ever tested by the U.S. Environmental Protection Agency [2]. … [2] Tier-2, Bin-2 and ILEV certification as of December 2013.”

[457] Review: “2012 Honda Civic Natural Gas.” By Michael Austin. Car and Driver, March 2012. <www.caranddriver.com>

[I]t’s the only factory-built CNG car in the country available to nonfleet customers. …

[T]he car’s supply of CNG is stored in a 3600-psi tank that sits behind the rear seats and cuts the trunk space in half, to six cubic feet. In energy equivalence, the Civic CNG holds about eight gasoline gallons’ worth of fuel. Honda lists a conservative range estimate of 220 miles. …

… [T]he Civic CNG makes 110 hp, 30 fewer than its gasoline counterpart. Torque drops by 22 lb-ft, to 106. …

… Honda charges $5650 more than for a similarly equipped Civic EX, or $26,925.

[458] Webpage: “Civic Natural Gas – Engineering.” American Honda Motor Company. Accessed September 4, 2013 at <automobiles.honda.com>

“Cargo Volume (cu. ft.) [=] 6.1”

[459] Webpage: “Civic – Engineering.” American Honda Motor Company. Accessed September 4, 2013 at <automobiles.honda.com>

“EX … 5-Speed Automatic Cargo Volume (cu ft) [=] 12.5”

[460] Review: “2012 Honda Civic NG.” By Wayne Cunningham. CNET, May 11, 2012. <reviews.cnet.com>

“A Civic EX-L goes an average of 422 miles on a full tank, while the Natural Gas version can only go, on average, 248 miles after its tanks have been topped off.”

[461] Calculated with data from:

a) Webpage: “Civic Natural Gas – Engineering.” American Honda Motor Company. Accessed September 4, 2013 at <automobiles.honda.com>

“5-Speed Automatic Transmission (City/Highway/Combined) [=] 27 city / 38 hwy/ 31 combined”

b) Webpage: “Civic – Engineering.” American Honda Motor Company. Accessed September 4, 2013 at <automobiles.honda.com>

“EX … 5-Speed Automatic (City/Highway/Combined) [=] 28/39/32”

c) “Clean Cities Alternative Fuel Price Report.” U.S. Department of Energy, August 1, 2013. <www.afdc.energy.gov>

Page 2: “Table 2. July 2013 Overall Average Fuel Prices on Energy-Equivalent Basis … Nationwide Average Price in Gasoline Gallon Equivalents … Gasoline [=] $3.65 … CNG [=] $2.14”

NOTE: An Excel file containing the data and calculations is available upon request.

[462] Calculated with data from:

a) Webpage: “Civic – EPA Mileage Ratings3/Fuel.” American Honda Motor Company. Accessed March 14, 2016 at <automobiles.honda.com>

“EX … Continuously Variable Transmission (M-CVT) … (City/Highway/Combined) [=] 31/41/35”

b) Webpage: “Build Your Civic Sedan.” American Honda Motor Company. Accessed March 14, 2016 at <automobiles.honda.com>

“2016 Civic Sedan EX Continuously Variable Transmission [=] $21,875 Total MSRP22 MSRP as built excluding tax, license, registration, and options. Includes $835.00 destination charge.”

NOTE: The $835 destination charge has been removed from the Civic EX MSRP, since it is excluded from the Civic CNG MSRP below.

c) Webpage: “Civic Natural Gas – Specifications.” American Honda Motor Company. Accessed March 14, 2016 at <automobiles.honda.com>

“Starting MSRP … Natural Gas [=] $26,740* … EPA Mileage Ratings3/Fuel … 5-Speed Automatic Transmission (City/Highway/Combined) [=] 27/38/31 … * MSRP excluding tax, license, registration, $835.00 destination charge and options. Dealer prices may vary.”

d) “Clean Cities Alternative Fuel Price Report, January 2015.” U.S. Department of Energy, March 17, 2015.

<www.afdc.energy.gov>

Page 3: “Table 2. January 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

e) “Clean Cities Alternative Fuel Price Report, April 2015.” U.S. Department of Energy, May 28, 2015. <www.afdc.energy.gov>

Page 3: “Table 2. April 2015 Overall Average Fuel Prices on Energy-Equivalent Basis”

f) “Clean Cities Alternative Fuel Price Report, July 2015.” U.S. Department of Energy, July 31, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, July 2015”

g) “Clean Cities Alternative Fuel Price Report, October 2015.” U.S. Department of Energy, December 10, 2015. <www.afdc.energy.gov>

Page 4: “Table 3. National Average Fuel Prices On An Energy-Equivalent Basis, October 2015”

NOTE: An Excel file containing the data and calculations is available upon request.

[463] Article: “Honda Civic Hybrid, Natural-Gas Models Eliminated After 2015.” By John Voelcker. Green Car Reports, June 16, 2015. <www.greencarreports.com>

… [T]wo members of today’s Civic lineup won’t survive into the new generation: the Honda Civic Hybrid, and the Honda Civic Natural Gas.

Honda executive vice-president John Mendel revealed that both models would be discontinued in a business update briefing for media yesterday. …

He … said Honda will cancel the Civic Natural Gas model (nee Civic GL).

The elimination is due to a combination of low gasoline prices—which have eliminated the price advantage of natural gas in many markets—and a lack of interest on the part of consumers.

The Civic Natural Gas, which is assembled on the same line as other North American Civics, has sold at an annual rate of just 700 cars in recent years.

Mendel expressed some frustration over the car’s fate.

“Honda has promoted CNG for many years, but customer demand remains quite small,” he said, “and there appears to be no real appetite on the part of competitors or policymakers to promoting it.”

“That, plus the negligible price different, mean that consumer demand just hadn’t developed as Honda hoped—and there seems little likelihood that the situation will change in coming years.”

[464] Webpage: “About Vivek Chandra.” By Vivek Chandra. Accessed March 11, 2016 at <natgas.info>

Vivek Chandra is the Principal of Kerogen Consultants, a boutique gas and energy advisory firm based in Melbourne, Australia. …

He has degrees from the Colorado School of Mines, USA (BSc. Geophysical Engineering), University of Pennsylvania, USA (MSc. Energy Management), the French Petroleum Institute (Graduate degree in Economics) and Deakin University, Australia (Masters in Commercial Law).

Vivek Chandra is the author of Fundamentals of Natural Gas, a bestselling hardcover book published by Pennwell, publishers of Oil and Gas Journal and other leading industry books and manuals.

[465] Webpage: “Gas Usage.” By Vivek Chandra. Accessed March 11, 2016 at <natgas.info>

Natural gas holds the greatest promise as a fuel for fleet vehicles that refuel at a central location, such as transit buses, short-haul delivery vehicles, taxis, government cars, and light trucks. There are currently approximately 65,000 natural gas vehicles (NGVs) in operation in the United States using CNG and LNG as their main fuels. There are an estimated 10 – 20 million vehicles around the world that use CNG and LPG as their primary fuel. Notable countries are (Argentina, Pakistan, Brazil, Italy, India, Iran, US (for CNG) and Italy, Australia and Japan (for LPG vehicles).

[466] Webpage: “Civic Natural Gas – Frequently Asked Questions.” American Honda Motor Company. Accessed March 17, 2016 at <automobiles.honda.com>

Because of moisture and other contaminants inherent in some natural gas supplies, and the inability of some home refueling systems to adequately dry the gas and remove contaminants, Honda does not currently recommend home refueling….

If your vehicle needs repair and, after being examined by an authorized Honda Civic Natural Gas automobile dealer, is found to have contamination in the fuel system or damage to the fuel system as a result of using sub-standard natural gas, your warranty claim for repairs may be denied.

[467] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Pages 5: “Oil and natural gas are found in a variety of geologic formations. Conventional oil and natural gas are found in deep, porous rock or reservoirs and can flow under natural pressure to the surface after drilling.”

[468] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35: “Oil and gas have long been produced from what are now called ‘conventional sources’: wells are drilled into the earth’s surface, and pressure that is naturally present in the field—possibly with help from pumps—is used to bring the fuel to the surface.”

[469] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1: “Shale is a sedimentary rock that is predominantly composed of consolidated clay-sized particles.”

Pages 5-6:

In contrast to the free-flowing resources found in conventional formations, the low permeability of some formations, including shale, means that oil and gas trapped in the formation cannot move easily within the rock. … [T]o extract shale oil and gas from the rock, fluids and proppants (usually sand or ceramic beads used to hold fractures open in the formation) are injected under high pressure to create and maintain fractures to increase permeability, thus allowing oil or gas to be extracted. Other formations, such as coalbed methane formations and tight sandstone formations,12 may also require stimulation to allow oil or gas to be extracted.13

The process to develop shale oil and gas is similar to the process for conventional onshore oil and gas, but shale formations may rely on the use of horizontal drilling and hydraulic fracturing—which may or may not be used on conventional wells.

12Conventional sandstone has well-connected pores, but tight sandstone has irregularly distributed and poorly connected pores. Due to this low connectivity or permeability, gas trapped within tight sandstone is not easily produced.

13For coalbed methane formations, the reduction in pressure needed to extract gas is achieved through dewatering. As water is pumped out of the coal seams, reservoir pressure decreases, allowing the natural gas to release (desorb) from the surface of the coal and flow through natural fracture networks into the well.

[470] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35:

Other geological structures in the United States—shale rock and tight sand formations—have long been known to contain oil and gas. But the fuels are trapped in these formations and cannot be extracted in the same way as from conventional sources. Instead, producers use a combination of horizontal drilling and hydraulic fracturing, or “fracking,” during which fluids are injected under high pressure to break up the formations and release trapped fossil fuels.

[471] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Within the United States, the oil and natural gas industry typically refers to tight oil production rather than shale oil production, because it is a more encompassing and accurate term with respect to the geologic formations producing oil at any particular well. EIA has adopted this convention, and develops estimates of tight oil production and resources in the United States that include, but are not limited to, production from shale formations.

[472] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 89: “Table 4.1 Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2009 … Tight Gas … Natural gas produced from a non-shale formation with extremely low permeability.”

[473] Report: “Drilling Sideways—A Review of Horizontal Well Technology and Its Domestic Application.” U.S. Energy Information Administration, April 1993. <www.eia.gov>

Page 1:

A widely accepted definition of what qualifies as horizontal drilling has yet to be written. The following combines the essential components of two previously published definitions:1

Horizontal drilling is the process of drilling and completing, for production, a well that begins as a vertical or inclined linear bore which extends from the surface to a subsurface location just above the target oil or gas reservoir called the “kickoff point,” then bears off on an arc to intersect the reservoir at the “entry point,” and, thereafter, continues at a near-horizontal attitude tangent to the arc, to substantially or entirely remain within the reservoir until the desired bottom hole location is reached.

Most oil and gas reservoirs are much more extensive in their horizontal (areal) dimensions than in their vertical (thickness) dimension. By drilling that portion of a well which intersects such a reservoir parallel to its plane of more extensive dimension, horizontal drilling’s immediate technical objective is achieved. That objective is to expose significantly more reservoir rock to the wellbore surface than would be the case with a conventional vertical well penetrating the reservoir perpendicular to its plane of more extensive dimension (Figure 1). The desire to attain this immediate technical objective is almost always motivated by the intended achievement of more important objectives (such as avoidance of water production) related to specific physical characteristics of the target reservoir.

Pages 4-5:

Even when drilling technique has been optimized for a target, the expected financial benefits of horizontal drilling must at least offset the increased well costs before such a project will be undertaken. In successful horizontal drilling applications, the “offset or better” happens due to the occurrence of one or more of a number of factors.

First, operators often are able to develop a reservoir with a sufficiently smaller number of horizontal wells, since each well can drain a larger rock volume about its bore than a vertical well could. When this is the case, per well proved reserves are higher than for a vertical well. An added advantage relative to the environmental costs or land use problems that may pertain in some situations is that the aggregate surface “footprint” of an oil or gas recovery operation can be reduced by use of horizontal wells.

Second, a horizontal well may produce at rates several times greater than a vertical well, due to the increased wellbore surface area within the producing interval. For example, in the Austin Chalk reservoir of Texas’ Giddings Field, under equal pressure conditions, horizontal completions of 500 to 2,200 foot HD produce at initial rates 2½ to 7 times higher than vertical completions.7 Chairman Robert Hauptfuhrer of Oryx Energy Co. noted that “Our costs in the [Austin] chalk now are 50 percent more than a vertical well, but we have three to five or more times the daily production and reserves than a vertical well.”8 A faster producing rate translates financially to a higher rate of return on the horizontal project than would be achieved by a vertical project.

Third, use of a horizontal well may preclude or significantly delay the onset of production problems (interferences) that engender low production rates, low recovery efficiencies, and/or premature well abandonment, reducing or even eliminating, as a result of their occurrence, return on investment and total return.

[474] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

“One reason why 3,000-to-5,000-foot horizontal laterals are employed in the United States is to increase the likelihood that a portion of the horizontal lateral will be sufficiently productive to make the well profitable.”

[475] Webpage: “Development of Radar Navigation and Radio Data Transmission for Microhole Coiled Tubing Bottomhole Assemblies.” U.S. Department of Energy, National Energy Technology Laboratory. Accessed August 27, 2013 at <netl.doe.gov>

[476] Report: “Drilling Sideways—A Review of Horizontal Well Technology and Its Domestic Application.” U.S. Energy Information Administration, April 1993. <www.eia.gov>

Page vii:

Horizontal drilling technology achieved commercial viability during the late 1980’s. Its successful employment, particularly in the Bakken Shale of North Dakota and the Austin Chalk of Texas, has encouraged testing of it in many domestic geographic regions and geologic situations. …

… The commercial viability of horizontal wells for production of natural gas has not been well demonstrated yet, although some horizontal wells have been used to produce coal seam gas.

Page viii:

An offset to the benefits provided by successful horizontal drilling is its higher cost. But the average cost is going down. By 1990, the cost premium associated with horizontal wells had shrunk from the 300- percent level experienced with some early experimental wells to an annual average of 17 percent. Learning curves are apparent, as indicated by incurred costs, as new companies try horizontal drilling and as companies move to new target reservoirs. It is probable that the cost premium associated with horizontal drilling will continue to decline, leading to its increased use.

Pages 7-8:

The modern concept of non-straight line, relatively short-radius drilling, dates back at least to September 8, 1891, when the first U.S. patent for the use of flexible shafts to rotate drilling bits was issued to John Smalley Campbell (Patent Number 459,152). While the prime application described in the patent was dental, the patent also carefully covered use of his flexible shafts at much larger and heavier physical scales “… such, for example, as those used in engineer’s shops for drilling holes in boiler-plates or other like heavy work. The flexible shafts or cables ordinarily employed are not capable of being bent to and working at a curve of very short radius …”

The first recorded true horizontal oil well, drilled near Texon, Texas, was completed in 1929.9 Another was drilled in 1944 in the Franklin Heavy Oil Field, Venango County, Pennsylvania, at a depth of 500 feet.10 China tried horizontal drilling as early as 1957, and later the Soviet Union tried the technique.11 Generally, however, little practical application occurred until the early 1980’s, by which time the advent of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies, particularly downhole telemetry equipment, had brought some kinds of applications within the imaginable realm of commercial viability.

Early Commercial Horizontal Wells

Tests, which indicated that commercial horizontal drilling success could be achieved in more than isolated instances, were carried out between 1980 and 1983 by the French firm Elf Aquitaine in four horizontal wells drilled in three European fields: the Lacq Superieur Oil Field (2 wells) and the Castera Lou Oil Field, both located in southwestern France, and the Rospo Mare Oil Field, located offshore Italy in the Mediterranean Sea. In the latter instance, output was very considerably enhanced.12 Early production well drilling using horizontal techniques was subsequently undertaken by British Petroleum in Alaska’s Prudhoe Bay Field, in a successful attempt to minimize unwanted water and gas intrusions into the Sadlerochit reservoir.13

The Recent Growth of Commercial Horizontal Drilling Taking a cue from these initial successes, horizontal drilling has been undertaken with increasing frequency by more and more operators. They and the drilling and service firms that support them have expanded application of the technology to many additional types of geological and reservoir engineering factor-related drilling objectives. Domestic horizontal wells have now been planned and completed in at least 57 counties or offshore areas located in or off 20 States.

Horizontal drilling in the United States has thus far been focused almost entirely on crude oil applications. In 1990, worldwide, more than 1,000 horizontal wells were drilled. Some 850 of them were targeted at Texas’ Upper Cretaceous Austin Chalk Formation alone.

Page 23: “As noted early on, most domestic horizontal wells have thus far been drilled in search of, or to produce, crude oil. There is no physical reason why they should not also be targeted for natural gas.”

[477] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 35: “[During fracking] fluids are injected under high pressure to break up the formations and release trapped fossil fuels.”

[478] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1: “[Hydraulic fracturing is] a process that injects a combination of water, sand, and chemical additives under high pressure to create and maintain fractures in underground rock formations that allow oil and natural gas to flow….”

Page 5: “[T]o extract shale oil and gas from the rock, fluids and proppants (usually sand or ceramic beads used to hold fractures open in the formation) are injected under high pressure to create and maintain fractures to increase permeability, thus allowing oil or gas to be extracted.”

Pages 9-13:

The next stage in the development process is stimulation of the shale formation using hydraulic fracturing. Before operators or service companies perform a hydraulic fracture treatment of a well, a series of tests may be conducted to ensure that the well, wellhead equipment, and fracturing equipment can safely withstand the high pressures associated with the fracturing process. Minimum requirements for equipment pressure testing can be determined by state regulatory agencies for operations on state or private lands. In addition, fracturing is conducted below the surface of the earth, sometimes several thousand feet below, and can only be indirectly observed. Therefore, operators may collect subsurface data—such as information on rock stresses20 and natural fault structures—needed to develop models that predict fracture height, length, and orientation prior to drilling a well. The purpose of modeling is to design a fracturing treatment that optimizes the location and size of induced fractures and maximizes oil or gas production.

To prepare a well to be hydraulically fractured, a perforating tool may be inserted into the casing and used to create holes in the casing and cement. Through these holes, fracturing fluid—that is injected under high pressures—can flow into the shale (fig. 2 shows a used perforating tool).

Fracturing fluids are tailored to site specific conditions, such as shale thickness, stress, compressibility, and rigidity. As such, the chemical additives used in a fracture treatment vary. Operators may use computer models that consider local conditions to design site-specific hydraulic fluids. The water, chemicals, and proppant used in fracturing fluid are typically stored on-site in separate tanks and blended just before they are injected into the well. Figure 3 provides greater detail about some chemicals commonly used in fracturing.

Figure 3: Examples of Common Ingredients Found in Fracturing Fluid

Fracking Fluid Ingredients

The operator pumps the fracturing fluid into the wellbore at pressures high enough to force the fluid through the perforations into the surrounding formation—which can be shale, coalbeds, or tight sandstone—expanding existing fractures and creating new ones in the process. After the fractures are created, the operator reduces the pressure. The proppant stays in the formation to hold open the fractures and allow the release of oil and gas. Some of the fracturing fluid that was injected into the well will return to the surface (commonly referred to as flowback) along with water that occurs naturally in the oil- or gas-bearing formation—collectively referred to as produced water. The produced water is brought to the surface and collected by the operator, where it can be stored on-site in impoundments, injected into underground wells, transported to a wastewater treatment plant, or reused by the operator in other ways.21 Given the length of horizontal wells, hydraulic fracturing is often conducted in stages, where each stage focuses on a limited linear section and may be repeated numerous times.

Once a well is producing oil or natural gas, equipment and temporary infrastructure associated with drilling and hydraulic fracturing operations is no longer needed and may be removed, leaving only the parts of the infrastructure required to collect and process the oil or gas and ongoing produced water. Operators may begin to reclaim the part of the site that will not be used by restoring the area to predevelopment conditions. Throughout the producing life of an oil or gas well, the operator may find it necessary to periodically restimulate the flow of oil or gas by repeating the hydraulic fracturing process. The frequency of such activity depends on the characteristics of the geologic formation and the economics of the individual well. If the hydraulic fracturing process is repeated, the site and surrounding area will be further affected by the required infrastructure, truck transport, and other activity associated with this process.

20Stresses in the formation generally define a maximum and minimum stress direction that influence the direction a fracture will grow.

21Underground injection is the predominant practice for disposing of produced water. In addition to underground injection, a limited amount of produced water is managed by discharging it to surface water, storing it in surface impoundments, and reusing it for irrigation or hydraulic fracturing.

[479] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

1940s Hydraulic fracturing first introduced to the petroleum industry.

1947 The first experimental hydraulic fracturing treatment conducted in Grant County, Kansas.

1949 The first commercial hydraulic fracturing treatment conducted in Stephens County, Oklahoma.

1950s Hydraulic fracturing becomes a commercially accepted process.

1955 More than 100,000 individual hydraulic fracturing treatments performed.

Late 1970s and early 1980s Shale formations, such as the Barnett in Texas and Marcellus in Pennsylvania, are known but believed to have essentially zero permeability and thus are not considered economic. Federally sponsored research seeks to improve ways to extract gas from unconventional formations, such as shale.

1980s to early 1990s Mitchell Energy combines larger fracture designs, rigorous reservoir characterization, horizontal drilling, and lower cost approaches to hydraulic fracturing to make the Barnett Shale economic.

[480] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

The advent of large-scale shale gas production did not occur until around 2000 when shale gas production became a commercial reality in the Barnett Shale located in north-central Texas. As commercial success of the Barnett Shale became apparent, other companies started drilling wells in this formation so that by 2005, the Barnett Shale alone was producing almost half a trillion cubic feet per year of natural gas.

[481] Article: “U.S. Gas Fields Go From Bust to Boom.” By Ben Casselman. Wall Street Journal, April 30, 2009. <online.wsj.com>

In the 1980s, Texas oilman George Mitchell began trying to produce gas from a formation near Fort Worth, Texas, known as the Barnett Shale. He pumped millions of gallons of water at high pressure down the well, cracking open the rock and allowing gas to flow to the surface.

Oklahoma City-based Devon Energy Corp. bought Mr. Mitchell’s company in 2002. It combined his methods with a technique for drilling straight down to gas-bearing rock, then turning horizontally to stay within the formation. Devon’s first horizontal wells produced about three times as much gas as traditional vertical wells.

[482] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 1:

For decades, the United States has relied on imports of oil and natural gas to meet domestic needs. As recently as 2007, the expectation was that the nation would increasingly rely on imports of natural gas to meet its growing demand. However, recent improvements in technology have allowed companies that develop petroleum resources to extract oil and natural gas from shale formations,1 known as “shale oil” and “shale gas,” respectively, which were previously inaccessible because traditional techniques did not yield sufficient amounts for economically viable production.

Page 2: “Early drilling activity in shale formations was centered primarily on natural gas, but with the falling price of natural gas companies switched their focus to oil and natural gas liquids, which are a more valuable product.”

Page 6:

The process to develop shale oil and gas is similar to the process for conventional onshore oil and gas, but shale formations may rely on the use of horizontal drilling and hydraulic fracturing—which may or may not be used on conventional wells. Horizontal drilling and hydraulic fracturing are not new technologies, as seen in figure 1, but advancements, refinements, and new uses of these technologies have greatly expanded oil and gas operators’ abilities to use these processes to economically develop shale oil and gas resources. For example, the use of multistage hydraulic fracturing within a horizontal well has only been widely used in the last decade.15

15Hydraulic fracturing is often conducted in stages. Each stage focuses on a limited linear section and may be repeated numerous times.

[483] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 83: “Table 4.1: Natural Gas Overview (Billion Cubic Feet)”

NOTE: An Excel file containing the data and calculations is available upon request.

[484] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 4: “In the United States, one of the keys to increasing natural gas production has been advances in the application of horizontal drilling and hydraulic fracturing technologies, which made it possible to develop the country’s vast shale gas resources and contributed to a near doubling of total U.S. technically recoverable natural gas resource estimates over the past decade.”

[485] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Because they have proven to be quickly producible in large volumes at a relatively low cost, tight oil and shale gas resources have revolutionized U.S. oil and natural gas production, providing 29 percent of total U.S. crude oil production and 40 percent of total U.S. natural gas production in 2012. …

The use of horizontal drilling in conjunction with hydraulic fracturing has greatly expanded the ability of producers to profitably produce oil and natural gas from low permeability geologic formations, particularly shale formations.

[486] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36: “Natural gas abundance potentially extends even beyond the United States. A recent study by the U.S. Geological Survey concluded that significant shale gas resources might also be available in other countries, including China and Argentina. But as with unconventional oil production in other countries, it is too early to assess whether the successes in U.S. shale gas production can be replicated elsewhere.”

[487] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Key positive above-the-ground advantages in the United States and Canada that may not apply in other locations include private ownership of subsurface rights that provide a strong incentive for development; availability of many independent operators and supporting contractors with critical expertise and suitable drilling rigs and, preexisting gathering and pipeline infrastructure; and the availability of water resources for use in hydraulic fracturing.

[488] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Globally, 32 percent of the total estimated natural gas resources are in shale formations….

[I]t is important to distinguish between a technically recoverable resource, which is the focus of this report, and an economically recoverable resource. Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current technology, regardless of oil and natural gas prices and production costs. Economically recoverable resources are resources that can be profitably produced under current market conditions.

[489] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 4: “In the United States, one of the keys to increasing natural gas production has been advances in the application of horizontal drilling and hydraulic fracturing technologies, which made it possible to develop the country’s vast shale gas resources and contributed to a near doubling of total U.S. technically recoverable natural gas resource estimates over the past decade.”

[490] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Pages 21-25:

The amount of technically recoverable shale gas resources in the United States has been estimated by a number of organizations, including EIA, USGS, and the Potential Gas Committee (see fig. 6). Their estimates were as follows:

• In 2012, EIA estimated the amount of technically recoverable shale gas in the United States at 482 trillion cubic feet.27 This represents an increase of 280 percent from EIA’s 2008 estimate.

• In 2011, USGS reported that the total of its estimates for the shale formations the agency evaluated in all previous years28 shows the amount of technically recoverable shale gas in the United States at about 336 trillion cubic feet. This represents an increase of about 600 percent from the agency’s 2006 estimate.

• In 2011, the Potential Gas Committee estimated the amount of technically recoverable shale gas in the United States at about 687 trillion cubic feet.29 This represents an increase of 240 percent from the Committee’s 2007 estimate. …

In 2012, EIA reduced its estimate of technically recoverable shale gas in the Marcellus Shale by about 67 percent. According to EIA officials, the decision to revise the estimate was based primarily on the availability of new production data, which was highlighted by the release of the USGS estimate. In 2011, EIA used data from a contractor to estimate that the Marcellus Shale possessed about 410 trillion cubic feet of technically recoverable gas. After EIA released its estimates in 2011, USGS released its first estimate of technically recoverable gas in the Marcellus in almost 10 years. USGS estimated that there were 84 trillion cubic feet of natural gas in the Marcellus—which was 40 times more than its previous estimate reported in 2002 but significantly less than EIA’s estimate. In 2012, EIA announced that it was revising its estimate of the technically recoverable gas in the Marcellus Shale from 410 to 141 trillion cubic feet. …

In addition to the estimates from the three organizations we reviewed, operators and energy forecasting consultants prepare their own estimates of technically recoverable shale gas to plan operations or for future investment. In September 2011, the National Petroleum Council aggregated data on shale gas resources from over 130 industry, government, and academic groups and estimated that approximately 1,000 trillion cubic feet of shale gas is available for production domestically. In addition, private firms that supply information to the oil and gas industry conduct assessments of the total amount of technically recoverable natural gas. For example, ICF International, a consulting firm that provides information to public- and private-sector clients, estimated in March 2012 that the United States possesses about 1,960 trillion cubic feet of technically recoverable shale gas. …

As with estimates for technically recoverable shale oil, estimates of the size of technically recoverable shale gas resources in the United States are also highly dependent on the data, methodologies, model structures, and assumptions used and may change as additional information becomes available. … As a result, production rates achieved to date may not be representative of future production rates across the formation. EIA reports that experience to date shows production rates from neighboring shale gas wells can vary by as much as a factor of 3 and that production rates for different wells in the same formation can vary by as much as a factor of 10. Most gas companies estimate that production in a given well will drop sharply after the first few years and then level off, continuing to produce gas for decades, according to the Sustainable Investments Institute and the Investor Responsibility Research Center Institute.

[491] Report: “Oil and Gas Supply Module of the National Energy Modeling System: Model Documentation 2014.” U.S. Energy Information Administration, July 2014. <www.eia.gov>

Page 6: “Proved reserves are the estimated quantities that analyses of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.”

[492] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>):

Economically recoverable resources are resources that can be profitably produced under current market conditions. The economic recoverability of oil and gas resources depends on three factors: the costs of drilling and completing wells, the amount of oil or natural gas produced from an average well over its lifetime, and the prices received for oil and gas production. Recent experience with shale gas in the United States and other countries suggests that economic recoverability can be significantly influenced by above-the-ground factors as well as by geology.

[493] Press release: “3 to 4.3 Billion Barrels of Technically Recoverable Oil Assessed in North Dakota and Montana’s Bakken Formation—25 Times More Than 1995 Estimate.” U.S. Department of the Interior, U.S. Geological Survey, April 10, 2008.

<www.usgs.gov>

“Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.”

[494] Report: “Oil and Gas Supply Module of the National Energy Modeling System: Model Documentation 2014.” U.S. Energy Information Administration, July 2014. <www.eia.gov>

Page 6: “Technically recoverable resources are those volumes considered to be producible with current recovery technology and efficiency but without reference to economic viability. Technically recoverable volumes include proved reserves and inferred reserves as well as undiscovered and other unproved resources. These resources may be recoverable by techniques considered either conventional or unconventional.”

[495] Report: “Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States.” U.S. Energy Information Administration, June 10, 2013. <www.eia.gov>

Executive summary (<www.eia.gov>): “Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current technology, regardless of oil and natural gas prices and production costs.”

[496] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Undiscovered Recoverable Reserves (Crude Oil and Natural Gas): Those economic resources of crude oil and natural gas, yet undiscovered, that are estimated to exist in favorable geologic settings.”

[497] Webpage: “Do we have enough oil worldwide to meet our future needs?” U.S. Energy Information Administration. Last updated December 9, 2014. <www.eia.gov>

An often cited, but misleading, measurement of future resource availability is the reserves-to-production ratio, which is calculated by dividing the volume of total proved reserves by the volume of current annual consumption. Proved reserves are an accounting concept that is based on known projects, and it is not an appropriate measure for judging total resource availability in the long term. Over time, global reserves will likely increase as new technologies increase production at existing fields and as new projects are developed.

[498] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Proved reserves include only estimated quantities of crude oil from known reservoirs, and therefore they are only a subset of the entire potential oil resource base. …

Proved reserves cannot provide an accurate assessment of the physical limits on future production but rather are intended to provide insight as to company-level or country-level development plans in the very near term. In fact, because of the particularly rigid requirements for the classification of resources as proved reserves, even the cumulative production levels from individual development projects may exceed initial estimates of proved reserves.

[499] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, Sep 5, 2012. <www.gao.gov>

Page 25: “[Proved] Reserves are key information for assessing the net worth of an operator. Oil and gas companies traded on the U.S. stock exchange are required to report their reserves to the Securities and Exchange Commission. According to an EIA official, EIA reports a more complete measure of oil and gas reserves because it receives reports of proved reserves from both private and publically held companies.”

[500] Press release: “3 to 4.3 Billion Barrels of Technically Recoverable Oil Assessed in North Dakota and Montana’s Bakken Formation—25 Times More Than 1995 Estimate.” U.S. Department of the Interior, U.S. Geological Survey, April 10, 2008.

<www.usgs.gov>

A U.S. Geological Survey assessment, released April 10, shows a 25-fold increase in the amount of oil that can be recovered compared to the agency’s 1995 estimate of 151 million barrels of oil. …

Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.

New geologic models applied to the Bakken Formation, advances in drilling and production technologies, and recent oil discoveries have resulted in these substantially larger technically recoverable oil volumes. About 105 million barrels of oil were produced from the Bakken Formation by the end of 2007.

[501] Calculated with data from the report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 91: “Table 4.2: Crude Oil and Natural Gas Cumulative Production and Proved Reserves, 1977-2010”

NOTE: An Excel file containing the data and calculations is available upon request.

[502] Report: “Oil and Gas Supply Module: Assumptions to the Annual Energy Outlook 2015.” U.S. Energy Information Administration, Office of Energy Statistics, September 2015. <www.eia.gov>

Pages 128–130:

Key assumptions

Domestic oil and natural gas technically recoverable resources

A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is the remaining technically recoverable resource [TRR], consisting of proved reserves [95] and unproved resources [96]. Estimates of TRR are highly uncertain, particularly in emerging plays where few wells have been drilled. Early estimates tend to vary and shift significantly over time as new geological information is gained through additional drilling, as long-term productivity is clarified for existing wells, and as the productivity of new wells increases with technology improvements and better management practices. TRR estimates used by EIA for each AEO [Annual Energy Outlook] are based on the latest available well production data and on information from other federal and state governmental agencies, industry, and academia. …

Table 9.2. Technically Recoverable U.S. Dry Natural Gas Resources as of January 1, 2013 (trillion cubic feet)

Total Technically Recoverable Resources … Total U.S. [=] 2,276.5 …

Note: Resources in other areas where drilling is officially prohibited are not included. The estimate of 32.9 trillion cubic feet of natural gas resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the Mid and Southern Atlantic OCS is also excluded from the technically recoverable volumes because leasing is not expected in these areas by 2040.

[503] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 83: “Table 4.1: Natural Gas Overview (Billion Cubic Feet) … 2015 … Natural Gas Production (Dry) [=] 27,091.4”

CALCULATION: 2,276,500,000,000,000 technically recoverable cubic feet / 27,091,400,000,000 dry gas production per year = 84.0 years

[504] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 83: “Table 4.1: Natural Gas Overview (Billion Cubic Feet) … 2015 … Supplemental Gaseous Fuels [=] 59.7 … Consumption [=] 27,472.9”

NOTE: “Supplemental gaseous fuels” include “synthetic natural gas, propane-air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural gas.” [“Glossary.” U.S. Energy Information Administration. Accessed March 23, 2016 at <www.eia.gov>]

CALCULATION: 2,276,500,000,000,000 technically recoverable cubic feet / (27,472,900,000,000 cubic feet of consumption per year – 59,700,000,000 cubic feet of supplemental gaseous fuels) = 83.0 years

[505] Calculated with data from the report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 50: “Table 7. World natural gas production by region and country in the Reference case, 2010-2040 (trillion cubic feet) … Total world … 2010 [=] 111.1”

CALCULATION: 21,897 trillion cubic feet of technically recoverable natural gas / 111.1 trillion cubic feet of natural gas production per year = 197.1 years

[506] Article: “Potential of gas hydrates is great, but practical development is far off.” U.S. Energy Information Administration, November 7, 2012. <www.eia.gov>

Methane hydrates (or gas hydrates) are cage-like lattices of water molecules containing methane, the chief constituent of natural gas. …

According to the United States Geological Survey, the world’s gas hydrates may contain more organic carbon than the world’s coal, oil, and other forms of natural gas combined. Estimates of the naturally occurring gas hydrate resource vary from 10,000 trillion cubic feet to more than 100,000 trillion cubic feet of natural gas.

[507] Calculated with data from the footnote above and the report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 50: “Table 7. World natural gas production by region and country in the Reference case, 2010-2040 (trillion cubic feet) … Total world … 2010 [=] 111.1”

CALCULATION: 10,000-100,000 trillion cubic feet of technically recoverable natural gas / 111.1 trillion cubic feet of natural gas production per year = 90-900 years

[508] Article: “Potential of gas hydrates is great, but practical development is far off.” U.S. Energy Information Administration, November 7, 2012. <www.eia.gov>

Methane hydrates (or gas hydrates) are cage-like lattices of water molecules containing methane, the chief constituent of natural gas. They may represent one of the world’s largest reservoirs of carbon-based fuel. However, with abundant availability of natural gas from conventional and shale resources, there is no economic incentive to develop gas hydrate resources, and no commercial-scale technologies to exploit them have been demonstrated.

Gas hydrates can be found under arctic permafrost, as well as beneath the ocean floor. They can also form during drilling and production operations. So far, gas hydrates have provided more problems than solutions. The formation of gas hydrates in deepwater production can hinder operations; managing or preventing their formation in deepwater oil and gas wells and pipelines has been a challenge for many decades, and addressing the existence of gas hydrates is a major part of planning for deepwater drilling and production. However, at some point in the future, gas hydrates could be a potential source of natural gas. …

… The U.S. Department of Energy recently selected 14 gas hydrate research projects to receive funding, building on a successful test in early 2012 in which a steady flow of natural gas was extracted from gas hydrates on Alaska’s North Slope. Japan is also conducting research on producing gas hydrates from deepwater basins near its shores.

[509] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Coal: A readily combustible black or brownish-black rock whose composition, including inherent moisture, consists of more than 50 percent by weight and more than 70 percent by volume of carbonaceous material.”

[510] Entry: “coal.” American Heritage Science Dictionary. Houghton Mifflin, 2005. <www.thefreedictionary.com>

“A dark-brown to black solid substance formed from the compaction and hardening of fossilized plant parts in the presence of water and in the absence of air. Carbonaceous material accounts for more than 50 percent of coal’s weight and more than 70 percent of its volume. Coal is widely used as a fuel, and its combustion products are used as raw material for a variety of products including cement, asphalt, wallboard and plastics.”

[511] Article: “coal.” Encyclopædia Britannica Ultimate Reference Suite 2004.

“Different varieties of coal arise because of differences in the kinds of plant material (coal type), degree of coalification (coal rank), and range of impurities (coal grade).”

[512] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

Different types of coal have different characteristics including sulfur content, mercury content, and heat energy content. Heat content is used to group coal into four distinct categories, known as ranks: anthracite, bituminous, subbituminous, and lignite (generally in decreasing order of heat content).

There are far more bituminous coal mines in the United States than the other ranks (over 90% of total mines), but subbituminous mines (located predominantly in Wyoming and Montana) produce more coal because their average size is much larger.

[513] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Coal Rank: The classification of coals according to their degree of progressive alteration from lignite to anthracite. In the United States, the standard ranks of coal include lignite, subbituminous coal, bituminous coal, and anthracite and are based on fixed carbon, volatile matter, heating value, and agglomerating (or caking) properties.

Lignite: The lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for steam-electric power generation. It is brownish-black and has a high inherent moisture content, sometimes as high as 45 percent. The heat content of lignite ranges from 9 to 17 million Btu per short ton on a moist, mineral-matter-free basis. The heat content of lignite consumed in the United States averages 13 million Btu per short ton, on the as-received basis (i.e., containing both inherent moisture and mineral matter).

Subbituminous Coal: A coal whose properties range from those of lignite to those of bituminous coal and used primarily as fuel for steam-electric power generation. It may be dull, dark brown to black, soft and crumbly, at the lower end of the range, to bright, jet black, hard, and relatively strong, at the upper end. Subbituminous coal contains 20 to 30 percent inherent moisture by weight. The heat content of subbituminous coal ranges from 17 to 24 million Btu per short ton on a moist, mineral-matter-free basis. The heat content of subbituminous coal consumed in the United States averages 17 to 18 million Btu per short ton, on the as-received basis (i.e., containing both inherent moisture and mineral matter).

Bituminous Coal: A dense coal, usually black, sometimes dark brown, often with well-defined bands of bright and dull material, used primarily as fuel in steam-electric power generation, with substantial quantities also used for heat and power applications in manufacturing and making coke. Bituminous coal is the most abundant coal in active U.S. mining regions. Its moisture content usually is less than 20 percent. The heat content of bituminous coal ranges from 21 to 30 million Btu per short ton on a moist, mineral-matter-free basis. The heat content of bituminous coal consumed in the United States averages 24 million Btu per short ton, on the as-received basis (i.e., containing both inherent moisture and mineral matter).

Anthracite: The highest rank of coal; used primarily for residential and commercial space heating. It is a hard, brittle, and black lustrous coal, often referred to as hard coal, containing a high percentage of fixed carbon and a low percentage of volatile matter. The moisture content of fresh-mined anthracite generally is less than 15 percent. The heat content of anthracite ranges from 22 to 28 million Btu per short ton on a moist, mineral-matter-free basis. The heat content of anthracite consumed in the United States averages 25 million Btu per short ton, on the as-received basis (i.e., containing both inherent moisture and mineral matter). Note: Since the 1980’s, anthracite refuse or mine waste has been used for steam-electric power generation. This fuel typically has a heat content of 15 million Btu per short ton or less.

[514] Article: “Carbon Dioxide Emission Factors for Coal.” B.D. Hong and E. R. Slatick. U.S. Energy Information Administration, Quarterly Coal Report, January-April 1994. Pages 1-8. <www.eia.gov>

The amount of heat emitted during coal combustion depends largely on the amounts of carbon, hydrogen, and oxygen present in the coal and, to a lesser extent, on the sulfur content. Hence, the ratio of carbon to heat content depends on these heat-producing components of coal, and these components vary by coal rank.

Carbon, by far the major component of coal, is the principal source of heat, generating about 14,500 British thermal units (Btu) per pound. The typical carbon content for coal (dry basis) ranges from more than 60 percent for lignite to more than 80 percent for anthracite. Although hydrogen generates about 62,000 Btu per pound, it accounts for only 5 percent or less of coal and not all of this is available for heat because part of the hydrogen combines with oxygen to form water vapor. The higher the oxygen content of coal, the lower its heating value.(3) This inverse relationship occurs because oxygen in the coal is bound to the carbon and has, therefore, already partially oxidized the carbon, decreasing its ability to generate heat. The amount of heat contributed by the combustion of sulfur in coal is relatively small, because the heating value of sulfur is only about 4,000 Btu per pound, and the sulfur content of coal generally averages 1 to 2 percent by weight.(4) Consequently, variations in the ratios of carbon to heat content of coal are due primarily to variations in the hydrogen content.

[515] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Coal … is formed from plant remains that have been compacted, hardened, chemically altered, and metamorphosed by heat and pressure over geologic time.”

[516] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 5:

People in China used coal as early as 3000 years ago, and there is evidence that Romans in England used coal for cooking in A.D. 100-200. …

When people in Europe discovered how useful coal was for heating, they quickly began to search for it, and they found it all around. By 1660, coal in England had become a booming business, and coal was exported around the world. Although English cities became very polluted by all the coal burning, the English preferred to put up with it, as they needed their wood for making charcoal. Charcoal was needed in large quantities for iron smelting, and the processing of other metals. Wood was also used in large quantities to build naval warships. …

By this time, [around 1700] most of Europe and especially England had cut down most of their forests. As they came to rely on coal for fuel, the demand for coal grew quickly. …

[517] Article: “coal.” Encyclopædia Britannica Ultimate Reference Suite 2004.

Coal was used commercially by the Chinese long before it was utilized in Europe. Although no authentic record is available, coal from the Fu-shun mine in northeastern China may have been employed to smelt copper as early as 1000 BC. …

Coal cinders found among Roman ruins in England suggest that the Romans were familiar with its use before AD 400. The first documented proof that coal was mined in Europe was provided by the monk Reinier of Liège, who wrote (about 1200) of black earth very similar to charcoal used by metalworkers. Many references to coal mining in England, Scotland, and the European continent began to appear in the writings of the 13th century. Coal was, however, used only on a limited scale until the early 18th century when Abraham Darby of England and others developed methods of using coke made from coal in blast furnaces and forges. Successive metallurgical and engineering developments—most notably the invention of the coal-burning steam engine by James Watt—engendered an almost insatiable demand for coal.

[518] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

“Coal remains the dominant fuel for the world’s thermal electric power plants. Coal has been the main thermal electric fuel due to its cheap price, worldwide availability, easy transport, and low-technology threshold.”

[519] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>

Page 95: “Coal is the predominant fuel used for electricity generation worldwide. In 2010, coal-fired generation accounted for 40 percent of overall worldwide electricity generation.”

[520] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>

Page 83:

Coal continues to be the largest single fuel used for electricity generation worldwide in the IEO2016 Reference case until the end of the projection period, with renewable generation beginning to surpass coal-fired generation in 2040. Coal-fired generation, which accounted for 40% of total world electricity generation in 2012, declines to 29% of the total in 2040 in the Reference case, despite a continued increase in total coal-fired electricity generation from 8.6 trillion kWh in 2012 to 9.7 trillion kWh in 2020 and 10.6 trillion kWh in 2040. Total electricity generation from coal in 2040 is 23% above the 2012 total.

[521] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated January 19, 2016.

<www.eia.gov>

The United States has the world’s largest estimated recoverable reserves of coal, and it is a net exporter of coal. In 2014, U.S. coal mines produced about 1 billion short tons of coal, the first increase in annual coal output in three years. More than 90% of the coal produced in the United States was used by U.S. power plants to generate electricity. Although coal has been the largest source of electricity generation in the United States for more than 60 years, its annual share of total net generation declined from nearly 50% in 2007 to 39% in 2014.

[522] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

“Besides its role in generating electricity, coal also has industrial applications in cement making and conversion to coke for the smelting of iron ore at blast furnaces to make steel. A small amount of coal is also burned to heat commercial, military, and institutional facilities, and an even smaller amount is used to heat homes.”

[523] Study Guide: “Coal.” U.S. Department of Energy, February, 24, 2010. <energy.gov>

Page 2:

Coal is also used in the industrial and manufacturing industries. The steel industry, for example, uses large amounts of coal. The coal is baked in hot furnaces to make coke, which is used to smelt iron ore into the iron needed for making steel. The very high temperatures created from the use of coke gives steel the strength and flexibility needed for making bridges, buildings, and automobiles.

Coal’s heat and by-products are also used to make a variety of products. For example, methanol and ethylene— ingredients in coal that can be separated out—can be used to make plastics, tar, synthetic fibers, fertilizers, and medicines.

[524] Article: “coal.” Encyclopædia Britannica Ultimate Reference Suite 2004.

“Coal is an abundant natural resource that can be used as a source of energy, as a chemical feedstock from which numerous synthetic compounds (e.g., dyes, oils, waxes, pharmaceuticals, and pesticides) can be derived, and in the production of coke for metallurgical processes.”

[525] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370): “Coke, Coal: A solid carbonaceous residue derived from low-ash, low-sulfur bituminous coal from which the volatile constituents are driven off by baking in an oven at temperatures as high as 2,000 degrees Fahrenheit so that the fixed carbon and residual ash are fused together. Coke is used as a fuel and as a reducing agent in smelting iron ore in a blast furnace. Coke from coal is gray, hard, and porous and has a heating value of 24.8 million Btu per short ton.”

[526] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>

Pages 81-83:

Many countries, particularly among the developed OECD nations are pursuing policies and regulations intended to increase the pressure on generators to reduce greenhouse gas emissions from electric power plants by decreasing the use of fossil fuels. As a result, the role of coal as a dominant fuel for electric power plants is being reduced. Since the last forecast cycle, there have been significant revisions to national clean energy policies to reduce emissions, including China’s target of 15% renewable electricity by 2020,164 the European Union’s 2030 Energy Framework objectives,165 and India’s megawatts-to-gigawatts renewable energy commitment.166 The IEO2016 Reference case analysis incorporates many updated targets that reflect the revised regulations and national energy policies that affect renewable energy. (See later sections for region- or fuel-specific revisions.) The effect of the recently finalized Clean Power Plan (CPP) regulations in the United States is not included in the IEO2016 Reference case, but its effects are considered in discussions, tables, and figures throughout the report, based on U.S. Energy Information Administration (EIA) analysis of the proposed rule, which had similar elements.

Given the recent history of renewable energy policy and the scale of current commitments, EIA evaluated the probability that stated targets would be met, based on: (1) data on the countries’ prior success in meeting renewable policy objectives, accounting for both the ambition and extent of fulfillment of targets; (2) indicators of the countries’ financial capability to build new projects; and (3) assessments of market pricing to support renewable energy sources. EIA adjusted the probabilities associated with successful implementation, with declining expectations dependent on how far into the future the target was specified.

The IEO2016 Reference case also reflects the impacts of broader policies to constrain energy-related carbon dioxide (CO2) emissions in emerging market countries, such as China and India. In those countries, policymakers have proposed a range of programs that place particular emphasis on the countries’ Intended Nationally Determined Contributions (INDCs) for addressing CO2 emissions reductions as part of the 21st Conference of Parties (COP21) meetings167 held in Paris from November 30 to December 11, 2015. In instances where the objective is clear but specific policy mechanisms are not yet known, judgment was applied to determine the likelihood that the intended outcomes would be achieved without attempting to predict specific actions. New and unanticipated government policies or legislation aimed at limiting or reducing greenhouse gas or other power-sector emissions, which could substantially change the trajectories of fossil and nonfossil fuel consumption, were not incorporated in the IEO2016 Reference case.

Table 5-1. OECD and non-OECD net electricity generation by energy source, 2012–40 (trillion kilowatthours)

Coal continues to be the largest single fuel used for electricity generation worldwide in the IEO2016 Reference case until the end of the projection period, with renewable generation beginning to surpass coal-fired generation in 2040. Coal-fired generation, which accounted for 40% of total world electricity generation in 2012, declines to 29% of the total in 2040 in the Reference case, despite a continued increase in total coal-fired electricity generation from 8.6 trillion kWh in 2012 to 9.7 trillion kWh in 2020 and 10.6 trillion kWh in 2040. Total electricity generation from coal in 2040 is 23% above the 2012 total.

China and India alone account for 69% of the projected worldwide increase in coal-fired generation, while the OECD nations continue to reduce their reliance on coal-fired electricity generation. With implementation of the Clean Power Plan, projections for U.S. coal-fired generation are reduced in 2030 by about one-third.

[527] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Coal3 [=] 16% … Industrial5 [=] 7% … Residential and Commercial6 [=] 1%6 … Electric Power7 [=] 37% …

3 Includes less than -0.02 quadrillion Btu of coal coke net imports.

5 Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants.

6 Includes commercial combined-heat-and-power (CHP) and commercial electricity-only plants.

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. Includes 0.2 quadrillion Btu of electricity net imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[528] Report: “Electric Power Annual 2014.” U.S. Energy Information Administration, Independent Statistics & Analysis, February 10, 2016. <www.eia.gov>

Page 66 (in PDF):

Table 4.1. Count of Electric Power Plants, by Sector, by Predominant Energy Sources within Plant, 2004 through 2014 … Total (All Sectors) … 2014 … Coal [=] 491 …

Notes: The number of power plants for each energy source is the number of sites for which the respective energy source was reported as the most predominant energy source for at least one of its generators. If all generators for a site have the same energy source reported as the most predominant, that site will be counted once under that energy source. However, if the most predominant energy source is not the same for all generators within a site, the site is counted more than once, based on the number of most predominant energy sources for generators at a site. In general, this table translates the number of generators by energy source into the number of sites represented by the generators for an energy source. Therefore, the count for Total (All Sectors) above is the sum of the counts for each sector by energy source and does not necessarily represent unique sites. In addition, changes to predominant energy sources and status codes from year to year may result in changes to previously-posted data.

Page 70 (in PDF):

Table 4.3. Existing Capacity by Energy Source, 2014 (Megawatts) … Energy Source … Coal … Number of Generators [=] 1,145 …

Notes: Coal includes anthracite, bituminous, subbituminous, lignite, and waste coal; coal synfuel and refined coal; and beginning in 2011, coal-derived synthesis gas.

[529] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <www-fusion.ciemat.es>

Page 27:

In an electrical generator electricity is made by turning a magnet in a magnetic field. The changing magnetic field drives the electrical current. With the exception of solar cells and fuel cells (which are discussed in chapters 4 and 6), all ways of generating electricity in some way drive a generator of this type. For example, fossil fuels are used to heat water into steam, which can be used to power a steam turbine. The steam turbine then drives the electrical generator.

A gas turbine works in a similar way: when the gas is ignited and starts to burn, it expands. The expanding gas is used to power an electrical generator through a turbine. In addition, the heat of the burning gas is then used to make steam, which powers a steam turbine.

This process is called combined cycle, and it has a high efficiency. If the waste heat of the steam turbine is also used, for example by a factory or for household heating, we have a Cogeneration Plant or Combined Heat and Power Plant.

[530] Booklet: What You Need to Know About Energy. National Academy of Sciences, 2008. Chapter: “Sources and Uses.” <www.nap.edu>

A typical coal-fired electrical plant might be 38% efficient, so a little more than one-third of the chemical energy content of the fuel is ultimately converted to usable electricity. …

In natural gas combined cycle, or NGCC, power plants, we now have technology that takes the waste heat from a natural gas turbine and uses it to power a steam turbine, resulting in a power plant that is as much as 60% efficient.5 Similar technologies are being developed for use in coal power plants.

[531] Dataset: “Primary Energy Consumption by Source and Sector, 2015 (Quadrillion Btu).” U.S. Energy Information Administration, Office of Energy Statistics, September 9, 2015. <www.eia.gov>

Coal3 [=] … Electric Power7 [=] 37% …

3 Includes less than -0.02 quadrillion Btu of coal coke net imports. …

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. Includes 0.2 quadrillion Btu of electricity net imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity).

[532] Calculated with data from the report: “June 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 27, 2016. <www.eia.gov>

Page 110: “Table 7.2b: Electricity Net Generation: Electric Power Sector”

NOTE: An Excel file containing the data and calculations is available upon request.

[533] Calculated with data from the report: “Electric Power Monthly with Data for January 2016.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2016. <www.eia.gov>

Page 15 (in PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2006–January 2016 (Thousand Megawatthours)”

NOTE: An Excel file containing the data and calculations is available upon request.

[534] Report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 97: “Table 6.1: Coal Overview (Thousand Short Tons) … 2015 … Coal Production (Thousand Short Tons) [=] 895,369.5 … Coal Consumption (Thousand Short Tons) [=] 801,562.9 … Coal Net Imports (Thousand Short Tons) [=] -62,639.9”

[535] Entry: “ton.” American Heritage Science Dictionary. Houghton Mifflin, 2005. Updated in 2009. <www.thefreedictionary.com>

“A unit of weight equal to 2,000 pounds (0.907 metric ton or 907.18 kilograms). Also called net ton, short ton.”

[536] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

“In 2009, coal began losing its price advantage over natural gas for electricity generation in some parts of the country, particularly in the eastern United States as a surge in natural gas production from domestic shale deposits (made possible by advances in drilling technologies) substantially reduced the price of natural gas.”

[537] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee/Northwest Natural Gas Association Planning Task Force, August 2012. <www.ferc.gov>

Page 3: “As emissions from coal-fired power plants have come under increasing public scrutiny, more and more electric utilities and merchant power producers have turned to natural gas for new baseload and peaking generation.”

[538] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 39:

Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally. …

At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated. …

In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:

• A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently

• Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas

• Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices

• Rising coal prices.

Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.

Page 41:

Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. … The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements. …

For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity (82). New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely. …

… Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.

[539] Article: “Coal-Heavy Indianapolis Getting a New Combined Cycle Plant.” By Thomas Overton. POWER, June 3, 2013. <www.powermag.com>

“The 341-MW coal-fired plant, which first came online in 1949, will shut down in March 2016. IPL [Indianapolis Power & Light] had concluded that replacing the plant made more economic sense than trying to bring it into compliance with Environmental Protection Agency (EPA) emissions regulations.”

[540] Calculated with data from the report: “March 2016 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 29, 2016. <www.eia.gov>

Page 97: “Table 6.1: Coal Overview (Thousand Short Tons)”

NOTE: An Excel file containing the data and calculations is available upon request.

[541] Dataset: “Coal Market Average Price.” U.S. Energy Information Administration. Accessed July 08, 2016 at <www.eia.gov>

“United States: Open Market”

[542] Calculated with data from:

a) Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Page 69: “Table 3.1: Fossil Fuel Production Prices, Selected Years, 1949-2011 … Coal Free on Board (F.O.B.) Rail/Barge Price”

b) Dataset: “Coal Market Average Price.” U.S. Energy Information Administration. Accessed July 08, 2016 at <www.eia.gov>

“United States: Open Market”

c) Report: “Electric Power Annual 2014.” U.S. Energy Information Administration February 2016. <www.eia.gov>

Page 143 in PDF): “Table 7.3. Average Quality of Fossil Fuel Receipts for the Electric Power Industry, 2004 through 2014.”

d) Dataset: “CPI Detailed Report Data for December 2015.” U.S. Department of Labor, Bureau of Labor Statistics, January 27, 2016. <www.bls.gov>

“Table 24. Historical Consumer Price Index for All Urban Consumers (CPI-U): U. S. city average, all items (1982-84=100, unless otherwise noted)”

NOTES:

- An Excel file containing the data and calculations is available upon request.

- EIA is no longer publishing the data for source (a), and the data for source (b) only extends back until 2001. Hence, Just Facts graphed both datasets to convey the general trends of natural gas prices over time.

[543] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>

Glossary (pages 349-370):

Captive Coal: Coal produced to satisfy the needs of the mine owner, or of a parent, subsidiary, or other affiliate of the mine owner (for example, steel companies and electricity generators), rather than for open market sale. See Open Market Coal. …

Open Market Coal: Coal sold in the open market, i.e., coal sold to companies other than the reporting company’s parent company or an operating subsidiary of the parent company. See Captive Coal. …

Free on Board (F.O.B.): A sales transaction in which the seller makes the product available for pick up at a specified port or terminal at a specified price and the buyer pays for the subsequent transportation and insurance.

Free on Board (F.O.B.) Rail/Barge Price: The free on board price of coal at the point of first sale. It excludes freight or shipping and insurance costs.

[544] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26:

Electricity peak loads in Kansas are the greatest during the summer months, primarily due to the electricity needs of air-conditioning systems. …

In order to cost-effectively meet the varying demand of their customers at different times of the year and even different times of the day, most utilities maintain a diverse portfolio of electric power plants (e.g., generating units) that use a variety of fuels. These generating units can be distinguished according to the type of power they produce (firm vs. intermittent) as well as the type of load they are designed to meet (base, peak, or intermediate).

[545] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“Electric power systems must match generation and load in real time, with tight tolerances. As a result, both system stress and prices can vary considerably throughout the day. … Load curve shapes vary among regions and change with the season of the year.”

[546] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 1:

“Whole-building electric load” is the total electrical power used by a building at a given moment. The load changes with time in response to changes in lighting levels; heating, ventilating, and air conditioning (HVAC) requirements; and uses such as computers, copy machines, and so on. The curve that represents load as a function of time, called the “load shape,” can often yield useful information. Unexpectedly high night-time loads may indicate waste (such as lights that needlessly remain on when the building is unoccupied); a change in load shape may indicate an equipment or thermostat malfunction; unexpectedly high sensitivity to outdoor temperature may indicate that excessive outdoor air is being brought into the building by the HVAC system; and so on.

[547] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 26: “Electricity consumption (also called ‘load’) is divided into three categories: base, peak, and intermediate load. Base load refers to demand that occurs continuously, day and night, seven days a week. Peak load, on the other hand, refers to maximum demand that occurs within a given period of time. Intermediate load is a more generic term applied to demand that occurs between base and peak load.”

[548] “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>

Peak load: The maximum load during a specified period of time.

Base load: The minimum amount of electric power delivered or required over a given period of time at a steady rate.

Base load capacity: The generating equipment normally operated to serve loads on an around-the-clock basis.

Base load plant: A plant, usually housing high-efficiency steam-electric units, which is normally operated to take all or part of the minimum load of a system, and which consequently produces electricity at an essentially constant rate and runs continuously. These units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs.

[549] Report: “Methods for Analyzing Electric Load Shape and its Variability.” By P. Price. Ernest Orlando Lawrence Berkeley National Laboratory, Environmental Energy Technologies Division, May 2010. <drrc.lbl.gov>

Page 22: “Figure 15: Sketch indicating five parameters that we recommend as a minimum set to characterize load shape. The value of each parameter can be calculated for each day; these values can then be summarized (e.g. average peak load, standard deviation of peak load).”

[550] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Historically, most base-load capacity has been provided using coal or nuclear technologies because, once the plants have been built, low fuel costs make them relatively cheap to operate continuously.”

Page 4: “Pulverized coal power plants, which burn solid coal ignited by injected air, are by far the most common option for generating base-load electricity.”

[551] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.kec.kansas.gov>

Page 27:

Power plants that are used to meet the minimum or “base load” of the system are referred to as base-load generating units; they are run continuously and operated, in general, so as to produce electricity at a constant rate. Base-load units are operated to maximize system mechanical and thermal efficiency and minimize system operating costs. Costs are minimized by operating units with the lowest fuel costs for the most hours in the year (i.e., at a high capacity factor). Generally, base-load units include nuclear, coal-fired, geothermal, hydropower, and waste-to-energy plants.63

[552] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

Coal remains the dominant fuel for the world’s thermal electric power plants. Coal has been the main thermal electric fuel due to its cheap price, worldwide availability, easy transport, and low-technology threshold. However, as stated above, Coal’s biggest drawback is the pollution emitted from its combustion. …

Typically, base load power stations are large nuclear, hydroelectric, or coal-burning plants that are expensive to build, with high fixed costs. However, they are cheap to maintain and operate. They operate continuously and are difficult to switch on or off.

[553] Webpage: “Gas Usage.” By Vivek Chandra (author of Fundamentals of Natural Gas, published by Pennwell, the publisher of Oil and Gas Journal and other leading industry books and manuals). Accessed February 3, 2016 at <natgas.info>

“The development of IPPs [Independent Power Producers] and the increased efficiency of gas-fired combined cycle plants have allowed gas to become the fuel of choice in both intermediate and peak load phases.”

[554] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 44: “In general, [natural gas] combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.”

[555] Report: “Nuclear Power’s Role in Generating Electricity.” Congressional Budget Office, May 2008. <www.cbo.gov>

Page 2: “Even though natural gas prices have increased significantly in recent years, natural gas remains the dominant source of peak capacity because power plants using that fuel are less expensive to build than coal-fired plants or nuclear reactors and easier to start up and shut down.”

[556] Webpage: “Demand for electricity changes through the day.” U.S. Energy Information Administration, April 6, 2011. <www.eia.gov>

“The transition from relatively lower loads to higher loads in the morning is called the ‘morning ramp’. This transition can stress power systems and lead to volatile prices. … Responding to such load changes often requires using units that can start up quickly. These units can be more expensive to operate than units that stay on for long periods such as baseload units. Power prices can increase during ramping, sometimes considerably, for short periods.”

[557] Brief: “What is the role of coal in the United States?” U.S. Energy Information Administration. Last updated July 18, 2012. <www.eia.gov>

“In 2009, coal began losing its price advantage over natural gas for electricity generation in some parts of the country, particularly in the eastern United States as a surge in natural gas production from domestic shale deposits (made possible by advances in drilling technologies) substantially reduced the price of natural gas.”

[558] Article: “On the Rise.” By Thomas Helbling. Finance & Development (International Monetary Fund), March 2013. Pages 34-37. <www.imf.org>

Page 36: “The main increased usage of gas has occurred in the U.S. power sector, where the share of electricity produced with natural gas has started to rise because many power plants can switch between gas and the now relatively more expensive (and dirtier) coal.”

[559] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee/Northwest Natural Gas Association Planning Task Force, August 2012. <www.ferc.gov>

Page 3:

In the United States, over the past decade, the single largest sector of natural gas demand growth has occurred in the area of power generation. As emissions from coal-fired power plants have come under increasing public scrutiny, more and more electric utilities and merchant power producers have turned to natural gas for new baseload and peaking generation. This trend has been accelerated in recent years, due to the boom of shale gas production, the relatively short lead time and low cost of natural gas-fired power plant construction, and the robust flexibility that natural gas-fired plants can bring to the area of Variable Energy Resource (VER) integration (i.e., wind and solar).

[560] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 39:

Over the past 20 years, natural gas has been the go-to fuel for new electricity generation capacity. From 1990 to 2011, natural gas-fired plants accounted for 77 percent of all generating capacity additions, and many of the plants added were very efficient combined-cycle plants. However, with slow growth in electricity demand and spikes in natural gas prices between 2005 and 2008, much of the added capacity was used infrequently. Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally. …

At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated. …

In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:

• A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently

• Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas

• Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices

• Rising coal prices.

Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.

Page 41:

Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. … The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements. …

For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity (82). New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely. …

… Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.

[561] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.eia.gov>

Page 3:

Although coal is expected to continue its important role in U.S. electricity generation, there are many uncertainties that could affect future outcomes. Chief among them are the relationship between coal and natural gas prices and the potential for policies aimed at reducing greenhouse gas (GHG) emissions. In 2012, natural gas prices were low enough for a few months for power companies to run natural gas-fired generation plants more economically than coal plants in many areas. During those months, coal and natural gas were nearly tied in providing the largest share of total electricity generation, something that had never happened before.

Page 40:

The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC [natural gas combined cycle] units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. … Because fuel prices vary by region, and because there is also considerable variation in efficiencies across the existing fleet of both coal-fired and combined-cycle plants, dispatch-level competition between coal and natural gas continues.

Page 43: “The delivered cost of coal in the [southeastern United States] region is somewhat higher than in many other regions. Central Appalachian and Illinois Basin coals must be transported by rail or barge to the Southeast, and coal from the Powder River Basin must travel great distances by rail. The region also uses some imported coal, typically along the Gulf Coast, which tends to be more expensive.”

Page 44:

In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region…. New England is located far from coal sources, and a regional cap on GHG [greenhouse gas] emissions is in place, which makes investment in new coal-fired capacity unlikely.

NOTE: Price variations in coal and natural gas are shown in the above graph of fossil fuel costs of electric power plants.

[562] Booklet: Energy, Powering Your World. By M.T. Westra and S. Kuyvenhoven. Foundation for Fundamental Research on Matter, Institute for Plasma Physics, Rijnhuizen (the Netherlands), 2002. <