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For example:
* “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]
* 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 293,000,000 Btu per person. To generate this amount of energy through physical human effort (like pedaling bicycles to drive generators) would require 197 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]
* In 2020, energy expenditures in the U.S. were $1.0 trillion ($1,007,433,000,000).[18] This amounts to:
* 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. Since 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.[26] [27] 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:
* Higher energy costs drive up the costs of food.[31] This has greater impacts on poorer nations and individuals because they spend a larger portion of their income on food.[32] [33] 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.[34]
* Per the Congressional Research Service, “The economic well-being and economic security of the nation depends on having stable energy sources.”[35]
* 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….”[36]
* Per the World Bank:
* Per the textbook Introduction to Air Pollution Science, “The availability of affordable electric power is essential for public health and economic prosperity.”[38]
* Per the U.S. Energy Information Administration:
* 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.”[41]
* 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:
* 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:
* In the U.S. from 1949 to 2021, energy consumption per inflation-adjusted dollar of economic output decreased by 67%:
* Homes built in the U.S. from 2000 to 2015 are about 25% 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.[49] [50]
* Homes built in the U.S. from 2000 to 2015 use about 23% more energy on appliances, electronics, and lighting than older homes. 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.”[51] [52]
* 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.[53] [54]
* Energy Star is a joint program of the U.S. Environmental Protection Agency (EPA) and Department of Energy. Per the program’s website:
* 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, two were rejected, and three were unanswered at the time the report was published. Among the products certified as Energy Star compliant were:
* 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.”[57] 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.”[58]
* In 2012, USA Today conducted an investigation of schools with green building certifications (such as LEED) and found that:
* In 1989, Gus Speth, president of environmentalist organization World Resources Institute, stated:
* As of 2022, the Mitsubishi Mirage is the most fuel-efficient non-hybrid car. It travels 39 miles per gallon of gasoline, has a 78-horsepower engine, and weighs about 2,100 pounds.[61] [62]
* Per the U.S. National Academy of Sciences:
* During 2023:
* The following charts show the components of U.S. energy consumption over time. The first shows consumption measured in Btus. The rest show consumption measured as a portion of total U.S. energy consumption. Each succeeding chart uses a smaller scale to provide increasing resolution.
* Data from the charts above:
|
Components of U.S. Energy Consumption |
|||||||||
|
Source |
1950 |
1960 |
1970 |
1980 |
1990 |
2000 |
2010 |
2020 |
2023 |
|
Fossil Fuels |
91.4% |
93.5% |
93.6% |
89.4% |
85.6% |
85.7% |
82.8% |
78.7% |
78.3% |
|
Petroleum |
38.4% |
44.1% |
43.5% |
43.8% |
39.7% |
38.7% |
36.2% |
34.8% |
35.9% |
|
Natural Gas |
17.2% |
27.5% |
32.1% |
25.9% |
23.2% |
24.1% |
25.2% |
34.0% |
34.1% |
|
Coal |
35.7% |
21.8% |
18.1% |
19.8% |
22.7% |
22.9% |
21.4% |
9.9% |
8.3% |
|
Renewables |
8.6% |
6.5% |
6.0% |
7.0% |
7.2% |
6.2% |
8.5% |
12.3% |
13.4% |
|
Wind |
N/A |
N/A |
N/A |
N/A |
0.0% |
0.1% |
0.9% |
3.2% |
3.8% |
|
Biofuels |
N/A |
N/A |
N/A |
N/A |
0.1% |
0.2% |
1.9% |
2.3% |
2.7% |
|
Solar |
N/A |
N/A |
N/A |
N/A |
0.1% |
0.1% |
0.1% |
1.3% |
2.2% |
|
Hydroelectric |
4.1% |
3.6% |
3.9% |
3.7% |
3.6% |
2.8% |
2.6% |
2.7% |
2.1% |
|
Wood |
4.5% |
2.9% |
2.1% |
3.2% |
2.6% |
2.3% |
2.3% |
2.1% |
1.9% |
|
Biowaste |
N/A |
N/A |
0.0% |
0.0% |
0.5% |
0.5% |
0.5% |
0.5% |
0.4% |
|
Geothermal |
N/A |
0.0% |
0.0% |
0.1% |
0.2% |
0.2% |
0.2% |
0.2% |
0.2% |
|
Nuclear |
0.0% |
0.0% |
0.4% |
3.5% |
7.2% |
8.0% |
8.6% |
8.9% |
8.2% |
* The U.S. Energy Information Administration (EIA) divides the energy market into four major sectors: residential,[78] commercial,[79] transportation,[80] and industrial.[81] [82]
* In 2021, the residential sector consumed 21% of all U.S. energy, the commercial sector consumed 18%, the transportation sector consumed 28%, and the industrial sector consumed 33%.[83]
* EIA sometimes classifies “electric power” as a separate sector,[84] although the electricity produced by this sector is consumed by the four major sectors.[85]
* In 2021, the electric power sector consumed 38% of all U.S. energy.[86]
* Per the Institute for Plasma Physics in the Netherlands:
* During 2021—amid the Covid-19 pandemic and related restrictions on business and personal activities:[88] [89] [90]
* Economic growth is a key factor in the growth of electricity generation.[93]
* 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.
* Excluding energy sources that are not commercially sold (like self-procured firewood), during 2020:
* During 2020:
* In both developing and developed countries, 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.[105] [106] [107] [108]
* 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:
* Per the journal Environmental Science & Technology:
* The air pollutants generated by energy sources vary with factors such as combustion methods, manufacturing techniques, and pollution control technologies.[113] [114] 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.[115] [116] [117]
* Environmental lifecycle analyses are subject to multiple levels of uncertainty.[118] [119] [120] [121]
* In general:
* Per the U.S. Department of Energy (2010):
* In the U.S. from 1990 through 2021, sulfur dioxide (SO2) emissions per Btu of coal-generated energy decreased by 94%, and nitrogen oxides (NOX) emissions decreased by 88%.[141]
* 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.”[142] [143] [144]
* The federal government and various states financially subsidize electric cars.[145] [146] Some states have also begun to mandate electric cars while claiming that they are “zero-emission vehicles.”[147] [148]
* Electric cars have no tailpipe emissions, but this does not mean they have no emissions. A study published by the Journal of Cleaner Production in 2021 found that electric cars emit more toxic emissions over their life cycles than gas cars. From “cradle-to-grave,” the study estimates that relative to gas cars, the manufacturing, usage, and disposal of electric cars will increase:
* Facts about air pollution levels and their effects are detailed in Just Facts’ research on pollution.
* Carbon dioxide (CO2) contributes more to the greenhouse effect than any other gas released by human activity.[150] [151] [152]
* In general:
|
Pounds of CO2 Per Million Btu |
|
|
Natural gas |
117 |
|
Propane |
139 |
|
Gasoline |
156 |
|
Diesel fuel & heating oil |
163 |
|
Coal |
205–229 |
* The federal government and various states financially subsidize electric cars.[166] [167] Some states have also begun to mandate electric cars while claiming that they are “zero-emission vehicles.”[168] [169]
* Electric cars have no tailpipe emissions, but this does not mean they have no emissions during their manufacturing, usage, and disposal. A study published by the Journal of Cleaner Production in 2021 found that from “cradle-to-grave,” electric cars emit 52% of the CO2 of gas cars.[170]
* 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.[171] [172] [173] [174] [175]
* Per the U.S. Congressional Budget Office, lifecycle analyses comparing CO2 emissions of corn-based ethanol and gasoline have produced varying results. 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.[176]
* 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 2022, producers have been unable to make enough of it to meet the mandated amounts specified in federal law.[177] [178] [179] [180] [181] [182] [183]
* 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:
* Per the U.S. Energy Information Administration:
* Facts about greenhouse gases and climate change are detailed in Just Facts’ research on global warming.
* 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% fewer miles per gallon than the same car when it is fueled with pure gasoline.[186] [187] [188] [189] [190]
* 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.[191]
* On an energy-equivalent basis, the average subsidized retail prices (including taxes) for transportation fuels during 2021 were as follows:
|
Fuel |
Nationwide Average Price in Gasoline-Gallon Equivalents |
Price Relative to Gasoline |
|
Compressed Natural Gas |
$2.23 |
-29% |
|
Biodiesel (B20) |
$2.60 |
-17% |
|
Diesel |
$2.78 |
-11% |
|
Gasoline |
$3.13 |
0% |
|
Ethanol (E85) |
$3.18 |
2% |
|
Biodiesel (B100) |
$3.47 |
11% |
|
Propane |
$4.08 |
30% |
* 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.[193] [194] [195] [196] [197]
* During 2021, a federal tax credit subsidized biodiesel at a rate of $1.00 per gallon.[198]
* During 2016, federal energy “subsidies” penalized petroleum and natural gas production at an average rate of $0.002 per gasoline-gallon equivalent.[199]
* Combining the data above yields the following average prices for transportation fuels during 2021 without federal subsidies:
|
Fuel |
Unsubsidized Price in Gasoline-Gallon Equivalents |
Unsubsidized Price Relative to Gasoline |
|
Compressed Natural Gas |
$2.23 |
-29% |
|
Diesel |
$2.78 |
-11% |
|
Biodiesel (B20) |
$2.92 |
-7% |
|
Gasoline |
$3.13 |
0% |
|
Propane |
$4.08 |
30% |
|
Ethanol (E85) |
$4.22 |
35% |
|
Biodiesel (B99–B100) |
$6.21 |
98% |
* A scientific, nationally representative survey commissioned in 2019 by Just Facts found that 40% of voters believed that the unsubsidized cost of ethanol or biodiesel was lower than gasoline.[202] [203] [204] In 2019, the unsubsidized cost of:
* 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 level through 2015.[206] [207]
* Since 1990, the inflation-adjusted average prices of electricity for all U.S. consumers and the four major energy sectors have varied as follows:
* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:
* 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.[212] [213]
* 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.[215] [216] [217] [218]
* 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.[219] [220] [221] [222]
* 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.[223] [224] [225] [226]
* Both coal and natural gas are competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[227] [228] [229] [230] [231]
* 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 equal to or less than 1.5 times the price of coal.[232] [233] [234] In 2021, the average price paid by electric power plants for natural gas was about 2.5 times the price of coal.[235]
* Determining which electricity-generating technologies will provide the lowest cost while maintaining reliability is complicated by the following factors:
* 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.”[255] [256] Per EIA:
* The following features, caveats, and limitations are inherent in EIA’s levelized costs:
* Based on the features, caveats, and limitations above, EIA’s 2022 levelized cost projections for plants beginning operation in 2027 are:
|
Plant Type (Lowest Cost Option From Each Major Category) |
Cost Per Megawatthour |
Cost Relative to Natural Gas |
|
Dispatchable Technologies |
||
|
Natural Gas Combined Cycle |
$40 |
0% |
|
Geothermal |
$40 |
0% |
|
Advanced Nuclear |
$88 |
121% |
|
Ultra-Supercritical Coal |
$83 |
107% |
|
Non-Dispatchable Technologies |
||
|
Onshore Wind |
$40 |
1% |
|
Offshore Wind |
$137 |
242% |
|
Hydropower |
$64 |
61% |
|
Photovoltaic Solar |
$36 |
–9% |
* Per EIA, “a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost.” Calculating these costs involves a greater degree of complexity than levelized costs.[294] [295]
* In July 2013, EIA published a preliminary discussion paper using avoided costs and levelized costs to compare the projected 2018 and 2035 economic values of advanced combined cycle natural gas, onshore wind, and PV solar.[296] Because there is significant variability in factors that affect electricity costs and values in different regions of the country, the paper assessed 22 regions of the United States. It found that without subsidies for wind and with a 10% tax credit for solar:
* The following features, caveats, and limitations are inherent in this analysis:
* In 2022, EIA used levelized costs and avoided costs to estimate which type of electricity plants would be economically competitive to build and begin producing electricity in 2027. Positive values indicate an economic incentive to build, and negative values indicate a disincentive:[309]
|
Levelized Avoided Costs Minus Levelized Costs ($ Per Megawatthour) |
||
|
Plant Type (Best Value From Each Major Category) |
Incentive |
Incentive Relative to Natural Gas |
|
Dispatchable Technologies |
||
|
Natural Gas Combined Cycle |
0 |
0 |
|
Geothermal |
5 |
6 |
|
Ultra-Supercritical Coal |
–44 |
–44 |
|
Advanced Nuclear |
–50 |
–49 |
|
Non-Dispatchable Technologies |
||
|
Onshore Wind |
–6 |
–5 |
|
Offshore Wind |
–101 |
–100 |
|
Hydropower |
–26 |
–26 |
|
Photovoltaic Solar |
–4 |
–3 |
* Forest product companies often use byproducts from their operations to generate their own electricity.[311] During 2021, wood generated 0.9% of all electricity in the U.S., as compared to 4.0% for solar and 0.4% for geothermal.[312]
* Oil and biofuels are rarely used to create electricity because they are significantly more costly than the major sources of electricity.[313] [314] In 2021, the average energy-equivalent price paid by electric power plants for petroleum was about 4.8 times the price of coal.[315]
* 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.[316] [317]
* 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.[318] [319] [320]
* Petroleum is mainly thought to be formed of diverse marine organisms that were buried by sediments and transformed by heat, pressure, and time.[321] [322] [323]
* The first oil well was drilled in 1857, the first intercontinental oil shipment occurred in 1861, 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.[324]
* 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.[325] [326] [327] [328] [329]
* 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.[330] [331]
* In 2021, petroleum supplied:
* In 2021, the U.S. produced about 6.9 billion barrels of petroleum, consumed about 6.8 billion barrels, and had net exports of about 60 million barrels.[334]
* U.S. petroleum consumption and net imports both peaked in 2005 and fell until 2012. From then until 2019, consumption rose, while net imports fell. These trends were primarily due to rising U.S. petroleum production from fracking, the Great Recession, efficiency improvements, and renewable fuel usage.[335] [336] [337] In 2020, U.S. consumption fell—primarily due to the Covid-19 pandemic—and the U.S. was a net exporter of petroleum.[338] [339] [340]
* Since 2005, U.S. petroleum production has risen by 128%, and net imports have fallen by 101%:
* In 2021, net petroleum imports from countries where the U.S. had a petroleum trading deficit were distributed as follows:
* 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.[347] [348] [349]
* 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.[350] [351] [352] [353] [354] [355] [356] [357]
* From 1960 to 2021, the U.S. imported an average of 1.2 billion barrels of petroleum per year from OPEC nations, ranging from a low of 0.3 billion in 2020 to a high of 2.3 billion in 1977:
* Crude oil prices are affected by global and local factors that impact the supply of petroleum and the demand for petroleum products, such as:
* In the U.S. during 2021, the average landed (i.e., delivered) price of crude oil from selected OPEC nations was 9% more than the average price of domestic crude, and the average landed price of crude from selected non-OPEC nations was 3% less than the average price of domestic crude.[366]
* In 2021, the average retail price of a gallon of regular-grade gasoline in the U.S. was $3.01. Broken down by its components:
* Crude oil resources can be grouped into four major categories based upon their accessibility:[368]
* 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.[383] [384]
* 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.[386]
* 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.[387] [388] [389] (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.[390]
* 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.[391] [392] [393] [394] [395] [396] The process is shown in this video:
* From 2005 to 2021, U.S. crude oil production increased by 128%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in tight oil formations.[397] [398] [399] [400] [401] [402] [403]
* In 2021, horizontal drilling coupled with hydraulic fracturing provided about 62% of total crude oil production in the U.S.[404] [405]
* As of 2021, horizontal drilling coupled with hydraulic fracturing has not been widely used to extract tight oil outside the U.S.[406] [407] [408] [409] [410] [411] [412] [413] [414] In 2013, the U.S. Energy Information Administration (EIA) estimated that 10% of worldwide technically recoverable oil resources are located in tight formations.[415]
* For facts about the environmental impacts of horizontal drilling and hydraulic fracturing, visit the fracking section of this research.
* Estimates of crude oil resources are uncertain and subject to change, particularly for tight oil formations.[416] [417] [418]
* Definitions used for estimates of fossil fuel resources include:
* Per the U.S. Energy Information Administration (EIA), it is “misleading” to make assessments about total fossil fuel resources on the basis of proved reserves. This is because:
* In 1955, America’s proved reserves of oil were equal to 11–12 years of U.S. oil consumption at that time.[429]
* 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.[430]
* In 1974, Stanford University professor and bestselling author Paul Ehrlich predicted that:
* From 1974 to 2021, annual global production of crude oil rose by 53%:
* As of 2020, EIA estimates that the U.S. has 373 billion barrels of technically recoverable crude oil. This figure does not include:
* 373 billion barrels of technically recoverable crude oil is roughly equivalent to:
* As of 2013, 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.[439]
* 3,357 billion barrels of technically recoverable crude oil is equivalent to 121 years of worldwide petroleum production at the 2013 production rate.[440]
* 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.[441]
* In 2010, the U.S. Department of the Interior reported that roughly 45% to 80% of oil shale reserves may be technically recoverable.[442]
* The largest known oil shale reserves are located in the Green River Formation, which is situated in southwestern Wyoming, northeastern Utah, and northwestern Colorado.[443] [444]
* 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 that roughly 8% to 27% of this has “a high potential for development.”[445] This amounts to:
* Per the U.S. Department of the Interior:
* Compiling the above estimates of technically recoverable crude oil and Green River oil shale with high potential for development:
* 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.[452] [453] [454]
* 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.[455]
* Natural gas is primarily comprised of organic compounds called hydrocarbons, which consist of carbon and hydrogen.[456]
* Natural gas is mainly thought to be formed of diverse marine organisms that were buried by sediments and transformed by heat, pressure, and time.[457] [458] [459]
* Natural gas and crude oil are often found in the same geological formations. In 2021, roughly 11% of all natural gas extracted from the ground in the U.S. came from crude oil wells.[460] [461]
* 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.[462]
* 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 under many conditions.[463] [464] [465]
* 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.[466] [467] [468] [469]
* 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).[470] [471] [472]
* 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%.[473]
* In 2020, 1.5% of U.S. natural gas production was vented or flared.[474] Worldwide in 2020, roughly 3.5% of natural gas production was flared (data on venting is unavailable).[475]
* 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.[476] [477] [478] [479] [480]
* In 2021, natural gas supplied:
* In 2021, the U.S. produced 34.1 trillion cubic feet of natural gas, consumed 30.3 trillion cubic feet, and had net exports of 3.8 trillion cubic feet:
* In the U.S. from 2007 to 2021, net imports of natural gas declined from 16% of the nation’s consumption to net exports equaling 13% of consumption. This is primarily due to increased domestic production through technologies known as horizontal drilling and hydraulic fracturing (described below):
* Natural gas prices are affected by factors that impact supply and demand, such as economic growth and recessions, weather, and technological advancements.[488] [489] [490] [491] 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.[492] [493] [494] [495] [496]
* In 2021, the average production price for natural gas was roughly $3.78 per thousand cubic feet, and the average price for residential consumers was $12.24 per thousand cubic feet.[497]
* In 2021, natural gas supplied 32% of the primary energy consumed in the U.S. electric power sector.[500] Because certain natural gas power plants are more efficient than coal power plants,[501] [502] and because some electricity is generated outside of the electric power sector, during 2021 natural gas supplied:
* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:
* 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.[508] [509]
* Natural gas is the dominant energy source for generating intermediate and peak load capacity because natural gas power plants:
* 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.[515] [516] [517]
* 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.[518] [519] [520] [521]
* Both coal and natural gas are competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[522] [523] [524] [525] [526] [527]
* 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 equal to or less than 1.5 times the price of coal.[528] [529] [530] In 2021, the average energy-equivalent price paid by electric power plants for natural gas was about 2.5 times the price of coal.[531]
* In 2021, natural gas supplied 4% of the energy used in the U.S. transportation sector.[532]
* 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.[533] [534] [535] [536] Steep declines in oil prices since 2014 have made natural gas less competitive as a transportation fuel.[537] [538] [539]
* Other disincentives to the wider use of natural gas in transportation include:
* Per the U.S. Energy Information Administration (EIA):
* 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.[546] It was the “cleanest internal-combustion vehicle ever tested by the U.S. Environmental Protection Agency.”[547] Compared to a similarly equipped Honda Civic EX, the natural gas model:
* Based on the average nationwide prices of gasoline and compressed natural gas in:
* In 2015, Honda announced it was cancelling the Civic Natural Gas after 2015 due to low gasoline prices and a lack of consumer demand.[555]
* Per Vivek Chandra, a natural gas industry consultant and the author of Fundamentals of Natural Gas:[556]
* Home fueling is possible with natural gas vehicles, but 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….”[558]
* Natural gas resources can be grouped into two major categories based upon their accessibility:
* 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.[565] [566]
* 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.[568]
* 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.[569] [570] (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.[571] [572]
* 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.[573] [574] [575] The process is shown in this video:
* From 2005 to 2021, U.S. natural gas production increased by 89%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in shale formations.[576] [577] [578]
* In 2021, horizontal drilling coupled with hydraulic fracturing provided about 77% of total dry natural gas production in the U.S.[579] [580]
* As of 2021, horizontal drilling coupled with hydraulic fracturing has not been widely used to extract natural gas outside the U.S.[581] [582] [583] [584] [585] [586] [587] In 2013, the U.S. Energy Information Administration (EIA) estimated that 32% of worldwide technically recoverable natural gas resources are located in shale formations.[588]
* For facts about the environmental impacts of horizontal drilling and hydraulic fracturing, visit the fracking section of this research.
* Estimates of natural gas resources are uncertain and subject to change, particularly for shale formations.[589] [590] [591]
* Definitions used for estimates of fossil fuel resources include:
* Per the U.S. Energy Information Administration (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.”[598] [599] [600] [601]
* 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.[602]
* As of 2020, EIA estimates that the U.S. has 2,926 trillion cubic feet of technically recoverable natural gas. This figure does not include resources located in “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.[603]
* 2,926 trillion cubic feet of technically recoverable natural gas is equivalent to:
* As of 2013, EIA estimates that the world has 22,882 trillion cubic feet of technically recoverable natural gas. This figure does not include several natural gas resources, such as offshore shale gas, shale gas formations in the Middle East and Caspian region, and other formations that have not yet been quantified by EIA.[606]
* 22,882 trillion cubic feet of technically recoverable natural gas is equivalent to 159 years of worldwide natural gas production at the 2021 production rate.[607]
* 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 as of 2012, these resources were estimated to be equivalent to 10,000–100,000 trillion cubic feet of natural gas, or 84–837 years of worldwide natural gas production at the 2012 production rate.[608] [609]
* Per EIA, methane hydrates:
* Coal is a class of combustible rocks that are at least 50% carbon by weight.[611] [612]
* 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.[613] [614] [615] [616]
* Coal is formed of plant materials that have been buried and transformed by pressure, heat, and time.[617]
* 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.[618] [619]
* Today, coal is the world’s leading fuel for generating electricity, due to attributes such as low cost and widespread availability.[620] [621]
* More than 90% of the coal produced in the U.S. is used to generate electricity.[622]
* Coal is also:
* Many nations have enacted polices to limit the use of coal in order to reduce greenhouse gases. Based upon these policies and other variables,[627] the U.S. Energy Information Administration projected in 2019 that:
* Coal accounted for 36% of global electricity production in 2021.[629] [630]
* In 2021, coal supplied:
* In 2020, the U.S. had 599 coal-fired electricity generating units located at 284 electric power plants.[633]
* Because coal power plants are less efficient than certain natural gas power plants,[634] [635] and because some electricity is generated outside of the electric power sector, during 2021 coal supplied:
* In 2021, the U.S. produced 577 million short tons of coal, consumed 546 million short tons, and had net exports of 80 million short tons.[639] [640]
* From 2008 to 2021, U.S. coal consumption declined by 52%, primarily as a result of lower natural gas prices and stricter environmental regulations:[641] [642] [643] [644]
* In 2020, the average domestic price of coal was $31.41 per ton.[646]
 |
* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:
* 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.[652] [653]
* 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.[655] [656] [657]
* Natural gas is the dominant energy source for generating intermediate and peak load capacity because:
* 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.[662] [663] [664] [665]
* Both coal and natural gas are competitive for generating baseload capacity under differing circumstances in different regions of the U.S.[666] [667] [668] [669] [670] [671]
* 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 equal to or less than 1.5 times the price of coal.[672] [673] [674] In 2021, the average energy-equivalent price paid by electric power plants for natural gas was about 2.5 times the price of coal.[675]
* In the U.S., coal is mined in two primary ways: surface mining and underground mining. Per the U.S. Department of Energy:
* In 2020, five U.S. coal workers were killed while working.[677] [678] In conjunction with technological advances, improved safety measures, and stricter regulations,[679] [680] coal worker fatalities have declined from a high of 3,242 people in 1907 to a low of 5 people in 2020:
* Per the Encyclopædia Britannica:
* Five countries have about 75% of the world’s coal resources, including:
* In 2020, the U.S. Energy Information Administration estimated that the U.S. has 252 billion short tons of recoverable coal reserves. These resources amount to:
* Based on U.S. Energy Information Administration estimates from 2011, the U.S. had 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:
* Based on U.S. Energy Information Administration estimates from 2021, there were roughly 1.2 trillion short tons of worldwide recoverable coal reserves. These resources amount to 123 years of coal production at the 2022 production rate.[690] [691]
* 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.[692] [693]
* 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.”[694] [695]
* 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.[696] The world’s first nuclear-powered electricity plant was built in the Soviet Union, and it became operational in 1954.[697]
* Through fission, a single pound of uranium can generate as much energy as burning three million pounds of coal.[698]
* In 2021, nuclear energy supplied 8.4% of all primary energy consumed in the United States:
* In 2021, nuclear energy generated 19% of all electricity produced in the U.S.[700]
* Demand for electricity varies on an hourly, daily, and seasonal basis due to factors such as:
* 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.[704] [705]
* 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.[707] [708] [709]
* 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.[710] [711] [712] [713] [714] [715]
* 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.[716] [717]
* 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.[718] [719] [720]
* The Nuclear Waste Policy Act of 1982 required the federal government to:
* 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:[726] [727]
* Current law limits the amount of fuel that could be stored at Yucca Mountain to 70,000 metric tons, which is equal to about 79% of the nation’s current commercial nuclear waste. Per evaluations performed by the Department of Energy, at least 3–4 times this limit can be safely stored at Yucca.[729] [730] [731] [732]
* 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.[733] [734] [735]
* A 2002 federal law approved the Yucca site for permanent nuclear waste storage.[736] [737]
* 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.[738] [739] [740]
* 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.[741]
* 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:
* 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.[744]
* From 1983 to 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.”[745]
* From 1983 to 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.”[746] [747]
* As of 2021, the U.S. had 88,248 metric tons of commercial nuclear waste, most of which was stored at nuclear power plants.[748] [749] [750] [751] [752]
* Due to a breach of its responsibility to start taking waste from power plants starting in 1998, the federal government has paid $9.0 billion in court-ordered damages and settlements to power plant operators as of September 2021.[753] [754]
* In 2021, the Inspector General of the Department of Energy estimated that the federal government’s total liabilities for breaching this responsibility will amount to $40 billion. The nuclear power industry estimates that it will be at least $50 billion.[755]
* 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.[756] [757]
* 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.[758] [759] [760]
* President Trump’s 2018–2020 budget blueprints called for funding to restart the Yucca Mountain program and provide for interim storage of nuclear waste.[761] [762] [763] [764] [765] [766] [767] [768] These provisions were not included in the budgets passed by Congress and signed by the president.[769] [770] [771]
* After Congress rejected President Trump’s calls for funding the Yucca Mountain program in the previous three years, his 2021 budget blueprint did not request funding for it.[772] [773]
* In 2021, the Biden administration announced that it is “beginning that process” to find a site for long-term nuclear waste storage and that Yucca Mountain is “off the table” as a potential site.[774]
* A commonly utilized measure of radiation dosage is millisieverts (mSv). On average, each person receives 2.4 mSv per year of natural background radiation per year, typically varying from 1 to 13 mSv. Per the United Nations Scientific Committee on the Effects of Atomic Radiation, “sizable population groups receive 10–20 mSv annually” of natural radiation. This does not include any radiation from human activities.[775] [776]
* Over the course of a lifetime, most people receive about 70–700 mSv of radiation from natural sources.[777]
* 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. The EPA estimates that 14% of lung cancer deaths in the U.S. are related to radon.[778]
* 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….”[779]
* Regarding manmade sources of radiation, on average:
* Concentrated (i.e., high-level, high-rate) radiation doses generally cause more harm than the same doses spread out over longer periods of time.[782] Concentrated radiation doses of:
* 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.[784]
* The largest nuclear power accident in the world occurred in the city of Chernobyl in the Soviet Union in 1986.[785] A picture of the reactor after the accident is shown here:
* 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:[787]
* Per the “environment” volume of the above-cited 2006 report:
* 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.[799] [800]
* A 2014 report about the Fukushima nuclear accident by the United Nations Scientific Committee on the Effects of Atomic Radiation found that:
* 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.[803]
* As a result of the Three Mile Island accident, the maximum radiation dosage to local residents was less than 1 mSv.[804] [805] [806] Per the U.S. Nuclear Regulatory Commission:
* 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.[809]
* The term “biomass” refers to non-fossil organic materials that can be used as energy sources.[810]
* There are three main types of biomass:
* 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.[820]
* 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.[821]
* In 2021, biomass supplied 5.0% of all primary energy consumed in the United States. Biofuels comprised 2.4 percentage points of this total, wood 2.1 percentage points, and biowaste 0.4 percentage point:
* In 2021, biomass supplied:
* Ethanol is the dominant biofuel in the U.S. and globally.[828] [829] [830] [831] [832] [833]
* In late 1970s, the federal government began promoting domestic biofuels by subsidizing the production of domestic ethanol and placing tariffs on ethanol imports.[834]
* Federal laws passed in 2005 and 2007 mandate that increasing volumes of biofuels be used in the U.S. transportation sector through 2022.[835] [836] [837] Due primarily to these laws,[838] [839] the portion of automotive fuel that is comprised of ethanol has risen from 2.9% in 2005 to 10.3% in 2021:
* Ethanol is another name for ethyl alcohol or grain alcohol, and it is chemically identical to the intoxicating ingredient in alcoholic beverages.[842] Before shipping ethanol, producers make it unfit for human consumption by adding inedible substances to it.[843]
* Ethanol has higher octane than gasoline, which increases engine power.[844] [845]
* The energy content per unit volume of ethanol is 31% below that of gasoline, which reduces fuel economy and hence vehicle range.[846] [847] [848]
* 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:
* 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.[850]
* 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.[851] [852]
* 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:[853]
* In 2016 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.[858] [859] Per the U.S. Energy Information Administration (EIA):
* 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.[862] [863]
* 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.[864] [865] [866] Per EPA:
* In the wake of EPA’s rulings, the following factors have limited the usage of E15:[868]
* In 2019 the Trump administration issued regulations that allow the year-round sale of E15.[877] [878] Prior to this, E15 could not be sold during summer months due to its potential to increase smog.[879]
* 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.[880] [881] [882]
* Due to the blend wall and other practical limitations on the usage of biofuels, the EPA has used its regulatory authority to reduce the amount of biofuels required by federal law from 2014 to 2021:
[883] [884] [885] [886] [887] [888] [889]
* 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.[890] Generally, the most economical and safest way to transport liquid fuels is through pipelines,[891] but wide-ranging technical and logistical issues currently prevent most ethanol from being transported in this manner.[892] [893]
* In 2016, EIA reported that biofuel production “often depends heavily on policies or mandates to support growth.”[894]
* In 2020, biofuels accounted for 6% of U.S. liquid fuels production (by volume) and 3% of global liquid fuels production.[895]
* In 2021, EIA projected that by 2050, biofuels will account for 3% of global liquid fuels production.[896] [897] [898]
* 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.[899] [900] [901] [902]
* 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.[903] [904] [905]
* For 2010, EPA reduced the law’s cellulosic biofuel mandate by 94%, but none of the fuel was actually produced.[906] [907]
* For 2011, EPA reduced the mandate by 98% and leveled fines of $6.8 million on motor fuel suppliers for failing to use the nonexistent fuel.[908] [909] [910] [911]
* For 2012, EPA reduced the mandate, but a federal appeals court struck it down because EPA had not used a “neutral methodology” to set the mandate.[912]
* 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.[913] [914] [915] In the year:
* From 2010 to 2021, the gaps between cellulosic biofuel production and the legislated mandate were as follows:
* In 2013, the EPA qualified a new fuel product (renewable gasoline blendstock) in the cellulosic biofuel class. This product accounted for all cellulosic biofuel production in 2013. The EPA has not published production data for renewable gasoline blendstock since 2014.[924] [925]
* In 2014, the EPA amended its cellulosic biofuel regulations to classify corn kernel fiber as a crop waste.[926]
* In 2014, the EPA amended its cellulosic biofuel regulations to include compressed and liquefied natural gas from renewable sources like landfills and wastewater treatment facilities.[927] [928] From 2014 to 2021, compressed and liquefied natural gas from renewable sources accounted for 96–99% of annual cellulosic biofuel production.[929]
* In 2015, the U.S. Department of Energy reported the results of a government-industry collaboration that produced a “cellulosic ethanol solution that meets the demands of renewable fuel and chemical producers for a cost effective, sustainable, scalable technology.”[930] [931] This technology prompted three companies (DowDuPont, POET, and Abengoa) to open commercial production facilities.[932] [933] [934] The Department of Energy called this “a huge step toward meeting the Department’s goals of”:
* As of September 2022:
* 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.[946] [947] [948]
* 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.[950] [951] [952] [953]
* Hydropower output typically varies from year to year because it is dependent upon rainfall and other elements of climate and weather.[954] In 2021, hydropower supplied 2.3% of all primary energy consumed in the United States:
* In 2021, hydropower generated 6.3% of all electricity produced in the U.S.[956]
* 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.[957] [958] [959] [960]
* 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.[961] [962] [963] [964]
* Per the U.S. Energy Information Administration’s Office of Energy Efficiency & Renewable Energy:
* Roughly 3% of the dams in the U.S. are used to generate hydropower. The rest are primarily used for recreation (38%), flood control (18%), water storage (17%), irrigation (11%), and other purposes (13%).[966] [967] [968]
* 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:
* 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.[970]
* 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:
* Wind power is harnessed by converting the energy of natural air movements into mechanical energy used to drive electric power generators, pumps, and mills.[973]
* More than 2,000 years ago, the Chinese used windmills to pump water. Around 600 A.D., Persians used windmills to grind grain.[975]
* From 1998 through 2021, the portion of U.S. primary energy supplied by wind grew from 0.03% to 3.4%:
* In 2021, wind generated 9.2% of all electricity produced in the U.S.[977]
* Ideally, commercial wind turbines should be located:
* 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.[983] [984] [985] Per the U.S. Energy Information Administration (EIA):
* Power capacity (a commonly cited statistic for wind energy installations[988]) 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.[989] [990] In the U.S. during 2010–2020, actual production from wind turbines was 32% of their power capacity.[991]
* 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.[992] [993] [994] [995] [996] [997] [998]
* 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.[999] [1000] [1001] [1002] [1003] [1004] Per EIA:
* As the amount of wind capacity rises in a given region, so do the challenges and costs of backing up its intermittent energy output.[1007] [1008] [1009] [1010] [1011] [1012] Reliance on wind as a major energy source can contribute to electricity blackouts during dangerous weather conditions.[1013] [1014] [1015] [1016] [1017]
* Solar power is harnessed by converting electromagnetic energy from the sun into heat or electricity. The current primary solar energy technologies include:
* 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.[1022]
* 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.[1023]
* 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.[1024] [1025] [1026] [1027]
* From 1984 through 2021, the portion of U.S. primary energy supplied by solar power grew from 0.0001% to 1.5%:
* In 2021, solar energy produced 3.9% of all electricity generated in the U.S.[1029]
* From 1998 to 2014, the average reported installed price for residential and commercial PV systems declined by about 6–12% per year.[1030]
* From 2000 to 2020, the median installed price for residential PV systems declined yearly on average by 6%.[1031]
* From 2007 to 2020, the median installed price for utility-scale PV systems declined yearly on average by 13%.[1032]
* Over the past two decades, residential and commercial PV system price declines were due primarily to technological advancements, economies of scale, and government subsidies.[1033] [1034] [1035] [1036] [1037] [1038] [1039]
* 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.[1040] Per a 2012 report by Lawrence Berkeley National Laboratory:
* Power capacity (a commonly cited statistic for solar energy installations[1042]) 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.[1043] [1044] [1045] In the U.S. during 2010–2020, actual production from utility-scale solar systems was 20% of their power capacity.[1046]
* 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.[1047] [1048] [1049] [1050] [1051] [1052] [1053]
* Because solar panels only generate electricity when the sun is shining, 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.[1054] [1055] [1056] [1057] [1058]
* As the amount of solar capacity rises in a given region, so do the costs of backing up its intermittent energy output.[1059] [1060] [1061] Reliance on solar as a major energy source can contribute to electricity blackouts during dangerous weather conditions.[1062] [1063] [1064] [1065] [1066]
* Geothermal energy is harnessed by transferring heat from or to the earth. The current main geothermal technologies include:
* Since ancient times, people have used hot springs for bathing, cooking, and heating.[1072]
* The world’s first electricity-generating geothermal plant was built in 1904 in Tuscany, Italy.[1073]
* From 1960 through 2021, the portion of U.S. primary energy supplied by geothermal power grew from 0.001% to 0.2%:
* In 2021, geothermal generated 0.4% of all electricity produced in the U.S.[1075]
* 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.[1076] [1077]
* Choosing between different forms of energy often involves tradeoffs between competing objectives, such as affordability, environmental impacts, and energy security. These tradeoffs are sometimes impossible to objectively quantify.[1078] [1079] [1080] [1081] [1082]
* A 2019 Reuters poll of 3,281 Americans found that 78% believed the government should “invest more money to develop clean energy sources such as solar, wind and geothermal.” When asked how much of the cost they were willing to bear:
* A 2010 Rasmussen poll of 1,000 likely voters found that:
* A 2008 Harris poll of 1,020 U.S. adults found that 92% favored “a large increase in the number of wind farms.”[1086] The same poll found that among 787 U.S. adults who pay household energy bills:
* During 2021, the average cost of ethanol without federal subsidies was 35% higher than gasoline, and the average cost of biodiesel without federal subsidies was 98% higher than gasoline.[1088]
* Per a 1992 report by the U.S. Energy Information Administration:
* “Subsidies,” as defined by the U.S. Government Accountability Office, are “payments or benefits provided to encourage certain desired activities or behaviors.”[1090]
* Per the U.S. Energy Information Administration (EIA), subsidies “stimulate the production or consumption of a commodity over what it would otherwise have been.”[1091]
* 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.[1092] [1093] [1094]
* The reasons that are given for enacting energy subsidies include but are not limited to:
* Other consequences of government energy subsidies include but are not limited to:
* Forms of energy subsidies include but are not limited to:
* Examples of subsidies for:
* As of September 2022, neither EIA nor the Congressional Budget Office (CBO) has published annual historical data providing a comprehensive and consistent measure of direct federal energy subsidies.[1168] [1169] [1170] [1171] [1172] [1173] 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.[1174] 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:
* 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.”[1179] Likewise, per EIA, “market impacts are negligible” for “programs that offer small subsidies for products for which there are huge existing markets….”[1180]
|
Year |
Direct Federal Energy Subsidies as a Portion of Total Energy Sales |
|
1990[1181] |
1–2% |
|
1999[1182] |
0.7% |
|
2007[1183] |
1.4% |
|
2010[1184] |
3.1% |
|
2013[1185] |
2.1% |
|
2016[1186] |
1.4% |
* 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.[1187] [1188]
* From 1985 through 2016, inflation-adjusted federal tax preferences for:
* 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.”[1191] [1192] For example, in 2010, coal received federal electricity production subsidies totaling $1,189 million, while solar received $968 million.[1193] However, coal produced 44.9% of the nation’s electricity, and solar produced 0.1%.[1194] [1195]
* From 1985 through 2016, inflation-adjusted federal tax preferences per unit of primary energy production for:
* 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.”[1198] [1199] For example:
* EIA has published comprehensive accountings of direct federal energy subsides for 1992, 1999, 2007, 2010, 2013, and 2016. Only the last four of these disaggregate subsidies for specific renewables, like wind, solar, and biofuels.[1210] [1211] [1212] [1213] [1214] [1215] Combining this data with EIA’s primary energy production data reveals the following levels of inflation-adjusted per-unit energy subsidies:
|
Direct Federal Energy Subsidies Per Billion Btu |
||||
|
2007 |
2010 |
2013 |
2016 |
|
|
Coal |
$185 |
$48 |
$55 |
$86 |
|
Natural Gas & Petroleum |
$67 |
$82 |
$63 |
-$15 |
|
Nuclear |
$221 |
$182 |
$169 |
$43 |
|
Geothermal |
$82 |
$399 |
$1,673 |
$410 |
|
Hydroelectric |
$76 |
$37 |
$91 |
$15 |
|
Solar |
$2,984 |
$12,334 |
$25,637 |
$3,923 |
|
Wind |
$1,524 |
$6,178 |
$3,864 |
$604 |
|
Biofuels |
$4,493 |
$3,930 |
$948 |
$1,237 |
* 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.[1218] However, EIA has noted that the outcomes of R&D subsidies are “inherently uncertain,” and:
* To reduce greenhouse gases, government officials and scientists have proposed increasing taxes on electricity,[1228] gasoline,[1229] crude oil,[1230] steel and aluminum,[1231] flying and driving,[1232] [1233] or any activity that emits carbon dioxide.[1234]
* Excise taxes are similar to sales taxes, except that they are imposed on specific goods and services.[1235] [1236]
* In addition to raising government revenue, excise taxes are sometimes levied to discourage or penalize certain activities.[1237] [1238] [1239] Per the U.S. Energy Information Administration:
* In 2022, excise taxes on gasoline averaged 57 cents per gallon across the United States. State governments collected 39 cents per gallon, and the federal government collected 18 cents.[1241]
* In 2020, state and federal governments collected about $87 billion in motor fuel excise taxes.[1242] This equates to 9% of total U.S. energy expenditures and 21% of U.S. transportation sector energy expenses.[1243]
* The economic burden of excise taxes primarily falls on retail customers in the form of higher prices. Per the Congressional Budget Office:
* From 2007 to 2017, companies in the S&P 500 paid an average of 30% in federal, state, local, and foreign corporate income taxes. Among energy sector companies in the S&P 500, the average corporate income tax rate was 37%.[1248] [1249]
* 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.[1250] [1251]
* The Congressional Budget Office (CBO) estimates that 75% of corporate income taxes are borne by owners/stockholders and 25% are borne by workers.[1252] Other creditable sources estimate that owners/stockholders bear anywhere from 33% to 100% of this tax burden.[1253] For more detail, see Just Facts’ research on tax distribution.
* Per the U.S. Energy Information Administration (EIA):
* 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.[1255] [1256] [1257]
* Regulation of hydropower plants has sometimes reduced output from wind farms.[1258]
* Regulations on the sulfur content of diesel fuel have played a role in raising the price of diesel above that of gasoline.[1259]
* The German government requires that renewable energy sources such as wind and solar replace all nuclear and coal plants in the country by 2038.[1260] To achieve this goal, the government has imposed fees and taxes on consumers and forced electrical grid operators to prioritize renewables over other energy sources.[1261] [1262] In Germany during 2021:
* As a result of surging energy costs caused by Germany’s “green energy” regulations:
* During a 2008 interview with the San Francisco Chronicle, Barack Obama stated:
* In 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.[1274] 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.[1275] The bill was then forwarded to the Senate and never voted upon.[1276]
* In 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.[1277] [1278]
* In 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.[1279] [1280] [1281]
* 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.”[1282]
* In 2019, the Trump administration repealed and replaced the Obama administration regulations that governed power plant CO2 emissions.[1283] [1284]
* In 2021, a federal appeals court cancelled the Trump administration regulations, but it did not clearly restore the Obama administration regulations.[1285] [1286] [1287]
* In 2022, the U.S. Supreme Court ruled that the EPA did not have “clear congressional authorization” to regulate power plant CO2 emissions.[1288]
* 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.[1289] [1290] [1291] Since 2003, the energy from fossil fuels produced on federal and American Indian lands has varied as follows:
* 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.[1293] [1294]
* An investigation published by the Associated Press in May 2014 found that:
* In November 2013, the Associated Press reported that the Obama administration:
* In December 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.[1297]
* 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.[1298]
* In December 2017, the Trump administration issued a ruling that states:
* In 2021, the Biden administration revoked the Trump administration’s ruling. The new rule will allow federal prosecution for the accidental injury or death of birds.[1302] [1303]
* 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.[1304] [1305] [1306] [1307]
* 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.[1308] [1309]
* 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.[1311]
* 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.[1312] [1313] (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.[1314] [1315]
* 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.[1316] [1317] [1318] The process is shown in this video:
* From 2005 to 2021, U.S. natural gas production increased by 89%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in shale formations.[1319] [1320] [1321] [1322] [1323]
* From 2005 to 2021, U.S. crude oil production increased by 128%, primarily due to the use of horizontal drilling coupled with hydraulic fracturing in tight oil formations.[1324] [1325] [1326] [1327] [1328] [1329] [1330]
* In 2019, the U.S. Energy Information Administration reported that conventional drilling was “becoming less common” and that “horizontal drilling combined with hydraulic fracturing have become standard practice for oil and natural gas production in the United States.”[1331] [1332]
* In 2021, horizontal drilling coupled with hydraulic fracturing provided about:
* Per a 2012 U.S. Government Accountability Office (GAO) report:
* 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.[1338]
* In areas that are rich in petroleum and natural gas (methane), these fuels commonly seep up to ground level through natural processes:
* 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.[1345] [1346]
* 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.[1347]
* 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.[1348] [1349]
* 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.”[1350]
* 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:
* 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.[1352]
[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. <fire.pppl.gov>
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>
Page 355:
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>
Page 350:
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.
[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. <fire.pppl.gov>
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 [mega joules] 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 (3rd 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. <nap.nationalacademies.org>
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 (Volume 28), 2002.
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. <fire.pppl.gov>
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: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “Table 1.7 Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Primary Energy Consumptiona … Consumption Per Capita (Million Btu) … 2021 [=] 293”
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. <fire.pppl.gov>
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) Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 18, 2013 at <www.eia.gov>
“1 Btu is approximately equal to 1,055 joules.”
CALCULATION: 293,000,000 Btu/year × 1,055 joules/Btu / 1,570,000,000 joules/person/year = 197 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. <fire.pppl.gov>
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) Webpage: “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:
[18] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “Table 1.7 Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Energy Expendituresb … Expenditures (Million Nominal Dollarsg) … 2020 [=] 1,007,433 … b Expenditures include taxes where data are available.”
[19] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “Table 1.7 Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Energy Expendituresb … Expenditures Per Capita (Nominal Dollarsg) … 2020 [=] 3,039 … b Expenditures include taxes where data are available.”
[20] Calculated with the dataset: “HH-1. Households by Type: 1940 to Present (Numbers in Thousands).” U.S. Census Bureau, Current Population Survey, November 2021. <www.census.gov>
“Year [=] 2020 … Total households [=] 128,451
CALCULATION: $1,007,433,000,000 energy expenditures / 128,451,000 households = $7,843 energy expenditures/household
[21] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “Table 1.7 Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators … Energy Expendituresb … Expenditures as Share of GDPe (Percent) … 2020 [=] 4.8 … b Expenditures include taxes where data are available. … R = Revised.”
[22] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “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 [Organization of Petroleum Exporting Countries] 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. <fas.org>
Page 2 (of PDF): “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] Calculated with data from:
a) Dataset: “Clean Cooking Access Database.” World Energy Outlook, International Energy Agency, 2021. <www.iea.org>
“Tab: “Summary”: Access to Clean Cooking, Summary by Region … Population Without Access (million) … World … 2020 [=] 2,585”
b) Dataset: “World Population Prospects 2022, Estimates 1950–2021.” United Nations, Population Division, Department of Economic and Social Affairs, July 2022. <population.un.org>
“Tab: “Estimates”: Region, Subregion, Country or Area [=] World … Population … Total Population, as of 1 January (thousands) … 2020 [=] 7,804,973.773”
CALCULATION: 2,585,000,000 without access / 7,804,973,773 population = 33%
[27] Article: “Defining Energy Access: 2020 Methodology.” International Energy Agency, October 13, 2020. <www.iea.org>
There is no single internationally-accepted and internationally-adopted definition of modern energy access. Yet significant commonality exists across definitions, including:
• Household access to a minimum level of electricity.
• Household access to safer and more sustainable (i.e. minimum harmful effects on health and the environment as possible) cooking and heating fuels and stoves.
• Access to modern energy that enables productive economic activity, e.g. mechanical power for agriculture, textile and other industries.
• Access to modern energy for public services, e.g. electricity for health facilities, schools and street lighting.
All of these elements are crucial to economic and social development, as are a number of related issues that are sometimes referred to collectively as “quality of supply,” such as technical availability, adequacy, reliability, convenience, safety and affordability.
However, due to data constraints, the data and projections presented in WEO [World Energy Outlook] focus on two elements of energy access: a household having access to electricity and to a relatively clean, safe means of cooking. These are measured separately. We maintain databases on levels of national, urban and rural electrification rates and on the proportion of the population without clean cooking access. Both databases are regularly updated and form the baseline for WEO energy access scenarios to 2040. …
Access to clean cooking facilities means access to (and primary use of) modern fuels and technologies, including natural gas, liquefied petroleum gas (LPG), electricity and biogas, or improved biomass cookstoves (ICS) that have considerably lower emissions and higher efficiencies than traditional three-stone fires for cooking. … For clean cooking, the database reports on the share of population without clean cooking access, defined as a household having primarily reliance on biomass, coal or kerosene for their cooking needs.
[28] 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. <fire.pppl.gov>
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.
[29] Webpage: “Household Air Pollution and Health” World Health Organization, July 26, 2022. <www.who.int>
Worldwide, around 2.4 billion people still cook using solid fuels (such as wood, crop waste, charcoal, coal and dung) and kerosene in open fires and inefficient stoves.1 Most of these people are poor and live in low- and middle-income countries.
Household air pollution is generated by the use of inefficient and polluting fuels and technologies in and around the home that contains a range of health-damaging pollutants, including small particles that penetrate deep into the lungs and enter the bloodstream. In poorly ventilated dwellings, indoor smoke can have levels of fine particles 100 times higher than acceptable. Exposure is particularly high among women and children, who spend the most time near the domestic hearth. Reliance on polluting fuels and technologies also require significant time for cooking on an inefficient device, and gathering and preparing fuel. …
Impacts on Health
Each year, 3.2 million people die prematurely from illnesses attributable to the household air pollution caused by the incomplete combustion of solid fuels and kerosene used for cooking (see household air pollution data for details). Particulate matter and other pollutants in household air pollution inflame the airways and lungs, impair immune response and reduce the oxygen-carrying capacity of the blood.
Among these 3.2 million deaths from household air pollution exposure:
• 32% are from ischaemic heart disease: 12% of all deaths due to ischaemic heart disease, accounting for over a million premature deaths annually, can be attributed to exposure to household air pollution;
• 23% are from stroke: approximately 12% of all deaths due to stroke can be attributed to the daily exposure to household air pollution arising from using solid fuels and kerosene at home;
• 21% are due to lower respiratory infection: exposure to household air pollution almost doubles the risk for childhood LRI and is responsible for 44% of all pneumonia deaths in children less than 5 years old. Household air pollution is a risk for acute lower respiratory infections in adults and contributes to 22% of all adult deaths due to pneumonia;
• 19% are from chronic obstructive pulmonary disease (COPD): 23% of all deaths from chronic obstructive pulmonary disease (COPD) in adults in low- and middle-income countries are due to exposure to household air pollution; and
• 6% are from lung cancer: approximately 11% of lung cancer deaths in adults are attributable to exposure to carcinogens from household air pollution caused by using kerosene or solid fuels like wood, charcoal or coal for household energy needs. …
Impacts on Health Equity, Development and Climate Change …
• Women and children disproportionately bear the greatest health burden from polluting fuels and technologies in homes as they typically labour over household chores such as cooking and collecting firewood and spend more time exposed to harmful smoke from polluting stoves and fuels.
• Gathering fuel increases the risk of musculoskeletal injuries and consumes considerable time for women and children – limiting education and other productive activities. In less secure environments, women and children are at risk of injury and violence while gathering fuel.
• Many of the fuels and technologies used by households for cooking, heating and lighting present safety risks. The ingestion of kerosene by accident is the leading cause of childhood poisonings, and a large fraction of the severe burns and injuries occurring in low- and middle-income countries are linked to household energy use for cooking, heating and lighting.2
• The lack of access to electricity for over 750 million1 people forces households to rely on polluting devices and fuels, such as kerosene lamps for lighting, thus making them exposed to very high levels of fine particulate matter.
• The time spent using and preparing fuel for inefficient, polluting devices constrains other opportunities for health and development, like studying, leisure time, or productive activities.
• Black carbon (sooty particles) and methane emitted by inefficient stove combustion are powerful short-lived climate pollutants (SLCPs).
• Household air pollution is also a major contributor to ambient (outdoor) air pollution.
[30] Report: “Energy Access Outlook 2017: From Poverty to Prosperity.” International Energy Agency, October 2017. <www.oecd.org>
Page 14: “[H]ouseholds relying on biomass for cooking dedicate around 1.4 hours each day collecting firewood, and several hours cooking with inefficient stoves, a burden largely borne by women.”
Page 26: “Access to energy services is critical for advancing human development, furthering social inclusion of the poorest and most vulnerable in society and to meeting many of the SDGs [sustainable development goals].”
Page 40:
Efforts to promote electricity access are having a positive impact in all regions, and the pace of progress has accelerated. Our analysis shows that the number of people without access to electricity fell to 1.1 billion people for the first time in 2016, with nearly 1.2 billion people having gained access since 2000…. However, despite the progress that has been made, 14% of the world’s population still lacks access to electricity, 84% of which live in rural areas.
Page 58: “There is a long way to go to achieve the 2030 objective of universal access to clean fuels and technologies for cooking…. Today, an estimated 2.8 billion do not have access to clean cooking facilities. A third of the world’s population—2.5 billion people—rely on the traditional use of solid biomass to cook their meals.”
[31] 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.
[32] 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
[33] 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.”
[34] Article: “Desperate Haitians Survive on Mud Cookies.” By Jonathan M. Katz. Associated Press, January 30, 2008. <www.cbsnews.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.
[35] 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.”
[36] 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.
[37] Webpage: “Metadata Glossary: Access to Electricity (% of Population).” World Bank. Accessed September 5, 2019 at <databank.worldbank.org>
Energy is necessary for creating the conditions for economic growth. It is impossible to operate a factory, run a shop, grow crops or deliver goods to consumers without using some form of energy. Access to electricity is particularly crucial to human development as electricity is, in practice, indispensable for certain basic activities, such as lighting, refrigeration and the running of household appliances, and cannot easily be replaced by other forms of energy. Individuals’ access to electricity is one of the most clear and un-distorted indication of a country’s energy poverty status.
[38] 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.”
[39] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 [gross domestic product] 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.
[40] Textbook: Microeconomics for Today (6th edition). By Irvin B. Tucker. South-Western Cengage Learning, 2010.
Page 450: “GDP [gross domestic product] 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.”
[41] Textbook: Microeconomics for Today (6th edition). By Irvin B. Tucker. South-Western Cengage Learning, 2010.
Page 450: “GDP [gross domestic product] 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.”
[42] 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. <fire.pppl.gov>
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.
[43] Booklet: “What You Need to Know About Energy.” National Academy of Sciences, 2008. <nap.nationalacademies.org>
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….
[44] Booklet: “What You Need to Know About Energy.” National Academy of Sciences, 2008. <nap.nationalacademies.org>
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.
[45] 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.”
[46] Article: “The Second Law of Thermodynamics.” New Encyclopaedia Britannica: Macropædia – Knowledge in Depth (Volume 28), 2002.
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.”
[47] 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.”
[48] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 19: “Table 1.7 Primary Energy Consumption, Energy Expenditures, and Carbon Dioxide Emissions Indicators”
[49] Calculated with data from the report: “2015 Residential Energy Consumption Survey.” U.S. Energy Information Administration, May 2018. <www.eia.gov>
“Table CE1.1 Summary Annual Household Site Consumption and Expenditures in the U.S.—Totals and Intensities, 2015”
“Table HC10.1 Total Square Footage of U.S. Homes, 2015”
NOTE: An Excel file containing the data and calculations is available upon request.
[50] 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 [U.S. Energy Information Administration] 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.
[51] Calculated with data from the report: “2015 Residential Energy Consumption Survey.” U.S. Energy Information Administration, May 2018. <www.eia.gov>
“Table CE3.1 Annual Household Site End-Use Consumption in the U.S.—Totals and Averages, 2015”
NOTE: An Excel file containing the data and calculations is available upon request.
[52] 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 [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.
[53] 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).”
[54] 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 [U.S. Energy Information Administration] survey data show that about 8% of households have a refrigerator that is at least 20 years old.
[55] 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 [Environmental Protection Agency] and US Department of Energy.
[56] 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>
Page 2 (of PDF):
GAO’s [U.S. Government Accountability Office] 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 [U.S. Department of Energy] and EPA [U.S. Environmental Protection Agency] 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 [Inspector General], 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:
[57] Webpage: “U.S. Green Building Council.” Accessed June 26, 2019 at <www.usgbc.org>
“The U.S. Green Building Council (USGBC) is a Washington, DC-based 501(c)(3) nonprofit organization committed to a prosperous and sustainable future for our nation through cost-efficient and energy-saving green buildings.”
[58] Webpage: “LEED.” U.S. Green Building Council. Accessed October 14, 2013 at <www.usgbc.org>
At its core, LEED [Leadership in Energy and Environmental Design] 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
[59] Article: “Green Schools: Long on Promise, Short on Delivery.” By Thomas Frank. USA Today, December 11. 2012. <www.usatoday.com>
The Houston Independent School District took a big step in 2007 toward becoming environmentally friendly by designing two new schools to meet a coveted “green” standard set by a private-builders’ group. …
But the schools are not operating as promised.
Thompson Elementary ranked 205th out of 239 Houston schools in a report last year for the district that showed each school’s energy cost per student. Walnut Bend Elementary ranked 155th. A third “green” school, built in 2010, ranked 46th in the report, which a local utility did for the district to find ways of cutting energy costs. …
Building a LEED [Leadership in Energy and Environmental Design]-certified school often adds 2% to 3% to construction costs, and as much as 10% in the case of a Selinsgrove, Pa., high school, state records show. …
“Green schools save money,” the [U.S. Green Building] council declares in an 80-page…. The conclusion is based on estimates made before construction of 30 green-certified schools—including Washington Middle School in Olympia, Wash., projected to use 28% less energy. The school consumed 19% more energy than a conventional school in its first two years, and 65% more than planned, a state report shows. …
More than 200 states, federal agencies and municipalities require LEED certification for public buildings. …
“Green schools help improve student performance,” the building council says in its legislators’ guide. …
USA TODAY found no clear pattern in a 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.
[60] Article: “Can the Human Race Be Saved?” By Gus Speth. U.S. Environmental Protection Agency EPA Journal, January/February 1989. Pages 47–50. <nepis.epa.gov>
Page 49:
The coming energy transformation, I would argue, must have rapid energy efficiency improvements as its dominant feature, supplemented by increased reliance on renewable energy sources. The potential for energy efficiency gains through technological change is simply enormous. If the efficiency in energy use currently in Japan today could be matched in the United States and around the world, total economic output could be doubled globally, and virtually doubled in the United States, without increasing energy use.
Auto efficiency provides a good example of what is possible. Miles per gallon achieved by new cars sold in the United States doubled from 13 mpg to 25 mpg between 1973 and 1985. Ford, Honda, and Suzuki all have cars in production that could double this again to 50 mpg, and Toyota has a prototype family car that could double efficiency again to almost 100 mpg. I am reminded here that there is a huge role for the private sector in the coming technological transformation. Those companies that see the future can profit from it.
Page 50: “Speth is President of the World Resources Institute†. This article is an excerpt from a speech Speth gave at EPA in June 1988.”
NOTE: † The World Resources Institute is a nonprofit organization with a mission to “move human society to live in ways that protect Earth’s environment….” [Webpage: “About Us.” World Resources Institute. Accessed June 15, 2021 at <www.wri.org>]
[61] Article: “Most Fuel-Efficient Cars (That Aren’t Electric or Hybrid).” By Austin Irwin. Car and Driver, March 22, 2022. <www.caranddriver.com>
“The most efficient car on the list gets 39 mpg combined, and another car can go 490 miles on a single tank of gas. … Mitsubishi Mirage: 39 mpg … Powered by a tiny, 1.2-liter 78-hp three-cylinder, the Mirage makes a big stand for fuel economy. With an EPA-rated 39 mpg combined for the CVT-equipped hatchback variant, this is certainly a case of David versus the gas station. … Horsepower: 78 horsepower”
[62] Webpage: “2022 Mitsubishi Mirage Black Edition CVT [continuously variable transmission] Features And Specs.” Car and Driver. Accessed July 27, 2022 at <www.caranddriver.com>
“Engine … Maximum Horsepower @ RPM [=] 78 @ 6000 … Weight Information … Base Curb Weight (pounds) [=] 2095”
[63] Booklet: “What You Need to Know About Energy.” National Academy of Sciences, 2008. <nap.nationalacademies.org>
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.
[64] 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.
[65] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[66] 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 [International Energy Agency] 2004). Examples include coal, crude oil, natural gas, solar power, nuclear power, etc.”
[67] Report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Pages 283–284:
Primary energy consumption: Consumption of primary energy. EIA includes the following in U.S. primary energy consumption: coal; coal coke net imports; petroleum consumption (equal to petroleum products supplied, excluding biofuels); dry natural gas—excluding supplemental gaseous fuels; nuclear electricity net generation (converted to Btu using the average annual heat rate of nuclear plants); conventional hydroelectricity net generation (converted to Btu using the heat content of electricity); geothermal electricity net generation (converted to Btu using the heat content of electricity), geothermal heat pump energy, and geothermal direct‐use thermal energy; solar thermal and photovoltaic electricity net generation (converted to Btu using the heat content of electricity), and solar thermal direct‐use energy; wind electricity net generation (converted to Btu using the heat content of electricity); wood and wood‐derived fuels; biomass waste; biofuels (fuel ethanol, biodiesel, renewable diesel, and other biofuels); losses and co‐products from the production of biofuels; electricity net imports (converted to Btu using the electricity heat content of 3,412 Btu per kilowatthour). Primary energy consumption includes all non‐combustion use of fossil fuels. Primary energy consumption also includes other energy losses throughout the energy system. See Total energy consumption. Energy sources 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. As a result, U.S. primary energy consumption does include net imports of coal coke, but it does not include the coal coke produced from domestic coal.
[68] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[69] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[70] 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…. Examples include coal, crude oil, natural gas, solar power, nuclear power, etc.”
[71] Report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Pages 283–284:
Primary energy consumption: Consumption of primary energy. EIA includes the following in U.S. primary energy consumption: coal; coal coke net imports; petroleum consumption (equal to petroleum products supplied, excluding biofuels); dry natural gas—excluding supplemental gaseous fuels; nuclear electricity net generation (converted to Btu using the average annual heat rate of nuclear plants); conventional hydroelectricity net generation (converted to Btu using the heat content of electricity); geothermal electricity net generation (converted to Btu using the heat content of electricity), geothermal heat pump energy, and geothermal direct‐use thermal energy; solar thermal and photovoltaic electricity net generation (converted to Btu using the heat content of electricity), and solar thermal direct‐use energy; wind electricity net generation (converted to Btu using the heat content of electricity); wood and wood‐derived fuels; biomass waste; biofuels (fuel ethanol, biodiesel, renewable diesel, and other biofuels); losses and co‐products from the production of biofuels; electricity net imports (converted to Btu using the electricity heat content of 3,412 Btu per kilowatthour). Primary energy consumption includes all non‐combustion use of fossil fuels. Primary energy consumption also includes other energy losses throughout the energy system. See Total energy consumption. Energy sources 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. As a result, U.S. primary energy consumption does include net imports of coal coke, but it does not include the coal coke produced from domestic coal.
[72] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[73] 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…. Examples include coal, crude oil, natural gas, solar power, nuclear power, etc.”
[74] Report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Pages 283–284:
Primary energy consumption: Consumption of primary energy. EIA includes the following in U.S. primary energy consumption: coal; coal coke net imports; petroleum consumption (equal to petroleum products supplied, excluding biofuels); dry natural gas—excluding supplemental gaseous fuels; nuclear electricity net generation (converted to Btu using the average annual heat rate of nuclear plants); conventional hydroelectricity net generation (converted to Btu using the heat content of electricity); geothermal electricity net generation (converted to Btu using the heat content of electricity), geothermal heat pump energy, and geothermal direct‐use thermal energy; solar thermal and photovoltaic electricity net generation (converted to Btu using the heat content of electricity), and solar thermal direct‐use energy; wind electricity net generation (converted to Btu using the heat content of electricity); wood and wood‐derived fuels; biomass waste; biofuels (fuel ethanol, biodiesel, renewable diesel, and other biofuels); losses and co‐products from the production of biofuels; electricity net imports (converted to Btu using the electricity heat content of 3,412 Btu per kilowatthour). Primary energy consumption includes all non‐combustion use of fossil fuels. Primary energy consumption also includes other energy losses throughout the energy system. See Total energy consumption. Energy sources 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. As a result, U.S. primary energy consumption does include net imports of coal coke, but it does not include the coal coke produced from domestic coal.
[75] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[76] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[77] Calculated with data from the report: “June 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2024. <www.eia.gov>
Page 258: “Table E3. Primary Energy Consumption by Source (Quadrillion Btu)” <www.eia.gov>
Page 259: “Table E4. Renewable Energy Production and Consumption by Source (Trillion Btu)” <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[78] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 28, 2022 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 [U.S. Energy Information Administration] programs differ in sectoral coverage.
[79] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 28, 2022 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.
[80] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 28, 2022 at <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 [U.S. Energy Information Administration] programs differ in sectoral coverage.
[81] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 28, 2022 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 [North American Industry Classification System] 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 [U.S. Energy Information Administration] programs differ in sectoral coverage.
[82] 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. <fire.pppl.gov>
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.
[83] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 38: “Table 2.1a Energy Consumption: Residential, Commercial, and Industrial Sectors (Trillion Btu)”
Page 39: “Table 2.1b Energy Consumption: Transportation Sector, Total End-Use Sectors, and Electric Power Sector (Trillion Btu)”
NOTE: An Excel file containing the data and calculations is available upon request.
[84] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 28, 2022 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 [U.S. Energy Information Administration] 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.
[85] 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.
[86] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 39: “Table 2.1b Energy Consumption: Transportation Sector, Total End-Use Sectors, and Electric Power Sector (Trillion Btu)”
NOTE: An Excel file containing the data and calculations is available upon request.
[87] 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. <fire.pppl.gov>
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!
[88] Article: “How Many Workers Are Employed in Sectors Directly Affected by Covid-19 Shutdowns, Where Do They Work, and How Much Do They Earn?” By Matthew Dey and Mark A. Loewenstein. U.S. Bureau of Labor Statistics Monthly Labor Review, April 2020. <www.bls.gov>
Page 1:
To reduce the spread of coronavirus disease 2019 (Covid-19), nearly all states have issued stay-at-home orders and shut down establishments deemed nonessential. Answering the following questions is crucial to assessing the potential labor market impacts of the shutdown policy: How many jobs are in the industries that are shut down? Where are these jobs located? What wages do they pay?
We provide answers to these questions by using data from the U.S. Bureau of Labor Statistics (BLS) Quarterly Census of Employment and Wages (QCEW) and Occupational Employment Statistics (OES) programs.1
[89] Working paper: “Tracking Labor Market Developments During the Covid-19 Pandemic: A Preliminary Assessment.” By Tomas Cajner and others. Board of Governors of the Federal Reserve System, Division of Research & Statistics and Monetary Affairs, April 15, 2020 <www.federalreserve.gov>
Page 2 (of PDF):
Many traditional official statistics are not suitable for measuring high-frequency developments that evolve over the course of weeks, not months. In this paper, we track the labor market effects of the Covid-19 pandemic with weekly payroll employment series based on microdata from ADP [a payroll processing firm]. These data are available essentially in real-time, and allow us to track both aggregate and industry effects. Cumulative losses in paid employment through April 4 are currently estimated at 18 million; just during the two weeks between March 14 and March 28 the U.S. economy lost about 13 million paid jobs. For comparison, during the entire Great Recession less than 9 million private payroll employment jobs were lost. In the current crisis, the most affected sector is leisure and hospitality, which has so far lost or furloughed about 30 percent of employment, or roughly 4 million jobs.
[90] “Monetary Policy Report.” Board of Governors of the Federal Reserve System, February 19, 2021. <www.federalreserve.gov>
Page 1:
The COVID-19 pandemic continues to weigh heavily on economic activity and labor markets in the United States and around the world, even as the ongoing vaccination campaigns offer hope for a return to more normal conditions later this year. While unprecedented fiscal and monetary stimulus and a relaxation of rigorous social-distancing restrictions supported a rapid rebound in the U.S. labor market last summer, the pace of gains has slowed and employment remains well below pre-pandemic levels.
Page 5:
The public health crisis spurred by the spread of COVID-19 weighed on economic activity throughout 2020, and patterns in the labor market reflected the ebb and flow of the virus and the actions taken by households, businesses, and governments to combat its spread. During the initial stage of the pandemic in March and April, payroll employment plunged by 22 million jobs, while the measured unemployment rate jumped to 14.8 percent—its highest level since the Great Depression….2 As cases subsided and early lockdowns were relaxed, payroll employment rebounded rapidly—particularly outside of the service sectors—and the unemployment rate fell back. Beginning late last year, however, the pace of improvement in the labor market slowed markedly amid another large wave of COVID-19 cases. The unemployment rate declined only 0.4 percentage point from November through January, while payroll gains averaged just 29,000 per month, weighed down by a contraction in the leisure and hospitality sector, which is particularly affected by social distancing and government-mandated restrictions.
[91] Calculated with data from the report: “Electric Power Monthly with Data for January 2022.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2022. <www.eia.gov>
Page 17 (of PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
Page 18 (of PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
NOTES:
[92] Calculated with data from the report: “Electric Power Monthly with Data for January 2022.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2022. <www.eia.gov>
Page 17 (of PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
Page 18 (of PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
NOTES:
[93] 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 [Organization for Economic Cooperation and Development] 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 [gross domestic product] 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 [International Energy Outlook] 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.
[94] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 131: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”
NOTE: An Excel file containing the data and calculations is available upon request.
[95] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 131: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”
NOTE: An Excel file containing the data and calculations is available upon request.
[96] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 131: “Table 7.2a. Electricity Net Generation: Total (All Sectors)”
NOTE: An Excel file containing the data and calculations is available upon request.
[97] Calculated with data from:
a) Dataset: “International Energy Outlook 2021, Delivered Energy Consumption by End-Use Sector and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 1, 2022 at <www.eia.gov>
b) Dataset: “International Energy Outlook 2021, Net Electricity Generation by Region and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 2, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[98] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>
Page ii: “Nonmarketed energy sources include selected energy consumption data for which the energy is not bought or sold, either directly or indirectly, as an input to marketed energy—particularly, traditional fuels such as fuelwood, charcoal, agricultural waste, and animal dung used for cooking and water heating. EIA [U.S. Energy Information Administration] does not estimate or project total consumption of nonmarketed energy.”
Page 87:
Global production of wood pellets has increased significantly over the past five years, and demand in the European Union (EU) has led to international trade in this renewable energy source. In 2013, the EU accounted for 85% of the world’s total consumption of wood pellets for energy production.183 Wood pellets can be used for heating homes and businesses and as a fuel for small-scale industrial boilers . In the United Kingdom, Belgium, and the Netherlands, they are used predominantly for utility-scale electricity generation.
Page 273: “[K]ey primary energy sources: several petroleum products, other liquid fuels, natural gas, coal, nuclear power, hydropower, wind, geothermal, solar, and other renewable sources (biomass, waste, and tide/wave/ocean).”
[99] Calculated with data from:
a) Dataset: “International Energy Outlook 2021, Delivered Energy Consumption by End-Use Sector and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 1, 2022 at <www.eia.gov>
b) Dataset: “International Energy Outlook 2021, Net Electricity Generation by Region and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 2, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[100] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>
Page ii: “Nonmarketed energy sources include selected energy consumption data for which the energy is not bought or sold, either directly or indirectly, as an input to marketed energy—particularly, traditional fuels such as fuelwood, charcoal, agricultural waste, and animal dung used for cooking and water heating. EIA [U.S. Energy Information Administration] does not estimate or project total consumption of nonmarketed energy.”
Page 87:
Global production of wood pellets has increased significantly over the past five years, and demand in the European Union (EU) has led to international trade in this renewable energy source. In 2013, the EU accounted for 85% of the world’s total consumption of wood pellets for energy production.183 Wood pellets can be used for heating homes and businesses and as a fuel for small-scale industrial boilers . In the United Kingdom, Belgium, and the Netherlands, they are used predominantly for utility-scale electricity generation.
Page 273: “[K]ey primary energy sources: several petroleum products, other liquid fuels, natural gas, coal, nuclear power, hydropower, wind, geothermal, solar, and other renewable sources (biomass, waste, and tide/wave/ocean).”
[101] Calculated with the dataset: “International Energy Outlook 2021, Net Electricity Generation by Region and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 2, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[102] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>
Page ii: “Nonmarketed energy sources include selected energy consumption data for which the energy is not bought or sold, either directly or indirectly, as an input to marketed energy—particularly, traditional fuels such as fuelwood, charcoal, agricultural waste, and animal dung used for cooking and water heating. EIA [U.S. Energy Information Administration] does not estimate or project total consumption of nonmarketed energy.”
Page 87:
Global production of wood pellets has increased significantly over the past five years, and demand in the European Union (EU) has led to international trade in this renewable energy source. In 2013, the EU accounted for 85% of the world’s total consumption of wood pellets for energy production.183 Wood pellets can be used for heating homes and businesses and as a fuel for small-scale industrial boilers . In the United Kingdom, Belgium, and the Netherlands, they are used predominantly for utility-scale electricity generation.
Page 273: “[K]ey primary energy sources: several petroleum products, other liquid fuels, natural gas, coal, nuclear power, hydropower, wind, geothermal, solar, and other renewable sources (biomass, waste, and tide/wave/ocean).”
[103] Calculated with the dataset: “International Energy Outlook 2021, Net Electricity Generation by Region and Fuel, Reference Case, Total World.” U.S. Energy Information Administration. Accessed August 2, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[104] Report: “International Energy Outlook 2016.” U.S. Energy Information Administration, May 2016. <www.eia.gov>
Page ii: “Nonmarketed energy sources include selected energy consumption data for which the energy is not bought or sold, either directly or indirectly, as an input to marketed energy—particularly, traditional fuels such as fuelwood, charcoal, agricultural waste, and animal dung used for cooking and water heating. EIA [U.S. Energy Information Administration] does not estimate or project total consumption of nonmarketed energy.”
Page 87:
Global production of wood pellets has increased significantly over the past five years, and demand in the European Union (EU) has led to international trade in this renewable energy source. In 2013, the EU accounted for 85% of the world’s total consumption of wood pellets for energy production.183 Wood pellets can be used for heating homes and businesses and as a fuel for small-scale industrial boilers . In the United Kingdom, Belgium, and the Netherlands, they are used predominantly for utility-scale electricity generation.
Page 273: “[K]ey primary energy sources: several petroleum products, other liquid fuels, natural gas, coal, nuclear power, hydropower, wind, geothermal, solar, and other renewable sources (biomass, waste, and tide/wave/ocean).”
[105] 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. <fire.pppl.gov>
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.
[106] Webpage: “Household Air Pollution and Health” World Health Organization, July 26, 2022. <www.who.int>
Worldwide, around 2.4 billion people still cook using solid fuels (such as wood, crop waste, charcoal, coal and dung) and kerosene in open fires and inefficient stoves.1 Most of these people are poor and live in low- and middle-income countries.
Household air pollution is generated by the use of inefficient and polluting fuels and technologies in and around the home that contains a range of health-damaging pollutants, including small particles that penetrate deep into the lungs and enter the bloodstream. In poorly ventilated dwellings, indoor smoke can have levels of fine particles 100 times higher than acceptable. Exposure is particularly high among women and children, who spend the most time near the domestic hearth. Reliance on polluting fuels and technologies also require significant time for cooking on an inefficient device, and gathering and preparing fuel.
[107] 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.
[108] 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.
[109] 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 [life cycle assessment] 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.
[110] Report: “Life-Cycle Greenhouse Gas Emissions of Transportation Fuels: Issues and Implications for Unconventional Fuel Sources.” IPIECA [International Petroleum Industry Environmental Conservation Association], 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.
[111] 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.
[112] Paper: “Energy Balance of the Global Photovoltaic (PV) Industry—Is the PV Industry a Net Electricity Producer?” By Michael Dale and Sally M. Benson. Environmental Science & Technology, February 26, 2013. Pages 3482–3489. <pubs.acs.org>
Page 3482:
A combination of declining costs and policy measures motivated by greenhouse gas (GHG) emissions reduction and energy security have driven rapid growth in the global installed capacity of solar photovoltaics (PV). This paper develops a number of unique data sets, namely the following: calculation of distribution of global capacity factor for PV deployment; meta-analysis of energy consumption in PV system manufacture and deployment; and documentation of reduction in energetic costs of PV system production. These data are used as input into a new net energy analysis of the global PV industry, as opposed to device level analysis. … Results suggest that the industry was a net consumer of electricity as recently as 2010. However, there is a >50% that in 2012 the PV industry is a net electricity provider and will “pay back” the electrical energy required for its early growth before 2020.
[113] Report: “Emission Factor Documentation for AP-42 Section 1.1: Bituminous And Subbituminous Coal Combustion.” By Acurex Environmental Corporation, Edward Aul & Associates, and E. 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. <nepis.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.”
[114] 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.”
[115] Report: “Electric Power Annual 2020.” U.S. Energy Information Administration, Assistant Administrator for Energy Statistics, October 29, 2021. Updated 3/10/22. <www.eia.gov>
Page 202 (of PDF): “Table A.1. Sulfur Dioxide Uncontrolled Emission Factors … Fuel … Bituminous Coal … Cyclone Firing Boiler [=] 38.00 [lbs. per ton] … Fluidized Bed Firing Boiler [=] 3.80 [lbs. per ton]”
[116] 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.
[117] Report: “Emission Factor Documentation for AP-42 Section 1.1: Bituminous And Subbituminous Coal Combustion.” By Acurex Environmental Corporation, Edward Aul & Associates, and E. 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. <nepis.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 [nitrogen oxides] 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.
[118] Presentation: “Uncertainty Analysis in LCA [life-cycle assessment] Concepts, Tools, and Practice.” By Reinout Heijungs. Leiden University, Institute of Environmental
Sciences, July 22, 2010. <formations.cirad.fr>
Pages 5–6 (of PDF):
What is uncertainty? (1)
Lots of meanings:
• incomplete information
• conflicting information
• linguistic imprecision
• variability
• errors …
What is uncertainty? (2)
Abundance of typologies and terminologies:
• systematic errors, random errors …
• data uncertainty, model uncertainty, completeness uncertainty …
• scenario uncertainty, parameter uncertainty, model uncertainty …
• uncertainty vs. accuracy vs. variability vs. sensitivity vs.…
[119] Paper: “Evaluating Uncertainty in Environmental Life-Cycle Assessment. A Case Study Comparing Two Insulation Options for a Dutch One-Family Dwelling.” By Mark A. J. Huijbregts and others. Environmental Science & Technology, May 29, 2003. Pages 2600–2608. <pubs.acs.org>
Abstract:
The evaluation of uncertainty is relatively new in environmental life-cycle assessment (LCA). It provides useful information to assess the reliability of LCA-based decisions and to guide future research toward reducing uncertainty. Most uncertainty studies in LCA quantify only one type of uncertainty, i.e., uncertainty due to input data (parameter uncertainty). However, LCA outcomes can also be uncertain due to normative choices (scenario uncertainty) and the mathematical models involved (model uncertainty).
[120] Report: “Environmental Decisions in the Face of Uncertainty.” National Academy of Sciences, Institute of Medicine, 2013. <www.nap.edu>
Page 1:
The U.S. Environmental Protection Agency (EPA) is one of several federal agencies responsible for protecting Americans against significant risks to human health and the environment. As part of that mission, EPA estimates the nature, magnitude, and likelihood of risks to human health and the environment; identifies the potential regulatory actions that will mitigate those risks and protect public health1 and the environment; and uses that information to decide on appropriate regulatory action. Uncertainties, both qualitative and quantitative, in the data and analyses on which these decisions are based enter into the process at each step.
[121] Article: “Background and Reflections on the Life Cycle Assessment Harmonization Project.” By Garvin A. Heath and Margaret K. Mann. Journal of Industrial Ecology, April 4, 2012. Pages S8–S11. <onlinelibrary.wiley.com>
Page S8:
Despite the ever-growing body of life cycle assessment (LCA) literature on electricity generation technologies, inconsistent methods and assumptions hamper comparison across studies and pooling of published results. Synthesis of the body of previous research is necessary to generate robust results to assess and compare environmental performance of different energy technologies for the benefit of pol-icy makers, managers, investors, and citizens. …
The LCA Harmonization Project’s initial focus was evaluating life cycle greenhouse gas (GHG) emissions from electricity generation technologies. Six articles from this first phase of the project are presented in a special supplemental issue of the Journal of Industrial Ecology on Meta-Analysis of LCA: coal (Whitaker and others 2012), concentrating solar power (Burkhardt and others 2012), crystalline silicon photovoltaics (PVs) (Hsu and others 2012), thin-film PVs (Kim and others 2012), nuclear (Warner and Heath 2012), and wind (Dolan and Heath2012).
Page S10:
Harmonization is a meta-analytical approach that addresses inconsistency in methods and assumptions of previously published life cycle impact estimates. It has been applied in a rigorous manner to estimates of life cycle GHG emissions from many categories of electricity generation technologies in articles that appear in this special supplemental issue, reducing the variability and clarifying the central tendency of those estimates in ways useful for decision makers and analysts.
[122] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated October 17, 2012. <www.justfacts.com>
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.
[123] 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 [greenhouse gas] 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 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 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 as SO2 [sulfur dioxide] and NOX [nitrogen oxides]. 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.
[124] 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 [photovoltaic] 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 [cadmium telluride] PV amounts to 89–98% reductions of GHG [greenhouse gas] 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.
[125] Webpage: “Geothermal Energy and the Environment.” U.S. Energy Information Administration. Last updated November 19, 2020. <www.eia.gov>
Geothermal power plants do not burn fuel to generate electricity, but they may release small amounts of sulfur dioxide and carbon dioxide. Geothermal power plants emit 97% less acid rain-causing sulfur compounds and about 99% less carbon dioxide than fossil fuel power plants of similar size. Geothermal power plants use scrubbers to remove the hydrogen sulfide naturally found in geothermal reservoirs. Most geothermal power plants inject the geothermal steam and water that they use back into the earth. This recycling helps to renew the geothermal resource and to reduce emissions from the geothermal power plants.
[126] 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>
Page 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.
Pages 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 as SO2 [sulfur dioxide] and NOX [nitrogen oxides]. 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.
[127] Webpage: “Geothermal Heat Pumps.” U.S. Energy Information Administration. Last reviewed November 19, 2020. <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 for heating and cooling buildings. All types of buildings, including homes, office buildings, schools, and hospitals, can use geothermal heat pumps.”
[128] Webpage: “Biofuels Explained: Biofuels and the Environment.” U.S. Energy Information Administration. Last reviewed April 13, 2022. <www.eia.gov>
When burned, pure biofuels generally produce fewer emissions of particulates, sulfur dioxide, and air toxics than their fossil-fuel derived counterparts. Biofuel-petroleum blends also generally result in lower emissions relative to fuels that do not contain biofuels. Biodiesel combustion may result in slightly higher amounts of nitrogen oxides relative to petroleum diesel.
Ethanol and ethanol-gasoline mixtures burn cleaner and have higher octane levels than gasoline that does not contain ethanol, but they also 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 blending with ethanol.
[129] 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.
[130] Webpage: “Ground-Level Ozone Standards Designations: Frequently Asked Questions.” U.S. Environmental Protection Agency. Last updated March 8, 2016. <archive.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.
[131] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
Biomass power plants emit nitrogen oxides and a small amount of sulfur 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.
[132] Paper: “A Review of the Environmental Impacts of Biobased Materials.” By Martin Weiss and others. Journal of Industrial Ecology, April 12, 2012. Pages S169–S181. <onlinelibrary.wiley.com>
Page S173:
A limited number of seven LCA [life cycle assessment] studies indicates that biobased materials may increase stratospheric ozone depletion by, on average, 1.9 ± 1.8 kg N2O-eq/t and 2.4 ± 1.3kg N2O-eq/(ha∗a) relative to their conventional counterparts (figure 1). The additional impacts thereby account, respectively, for 28 ± 26% and 35 ± 18% of the worldwide average per capita ozone depletion potential in the year 2000.The impacts in this category largely result from N2O [nitrous oxide] emissions that originate from fertilizer application in agriculture (Muller-Samannand others 2002; Wurdinger and others 2002). Because fertilizer application is characteristic for industrial farming used for growing biomass, high stratospheric ozone depletion potentials may be found for a wide range of biobased materials.
Pages S176–177:
• Biobased materials generally exert lower environmental impacts than conventional materials in the category of climate change (if GHG [greenhouse gas] emissions from indirect land use change are neglected).
• Biobased materials may exert higher environmental impacts than their conventional counterparts in the categories of eutrophication and stratospheric ozone depletion; our results are inconclusive with regard to acidification and photochemical ozone formation. …
• The GHG emissions savings identified here are uncertain because the reviewed LCA studies (1) may only insufficiently account for N2O emissions from biomass cultivation and (2) exclude the effects of indirect land use change. Depending on product scenarios and time horizons, especially the latter factor may substantially lower the established GHG emissions savings. Further research is needed.
[133] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
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 [carbon monoxide] output by 90% to 97% and CO2 [carbon dioxide] by 25%. The switch can also significantly reduce NOX [nitrogen oxides] emissions, as well as nonhydrocarbon emissions and particulates.
[134] 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. <fire.pppl.gov>
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.”
[135] 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.”
[136] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
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.
[137] 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 Agency2. … 2 EPA [Environmental Protection Agency] Tier-2, Bin-2 and ILEV [Inherently Low Emission Vehicle] certification as of December 2013.”
[138] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated October 17, 2012. <www.justfacts.com>
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 MWh) |
||
|
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).
[139] 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.
[140] Presentation: “Changes in Control Technologies at Coal-Fired Units: 2000–2016.” U.S. Environmental Protection Agency, 2016. <www.epa.gov>
Page 1: “2000 Coal Controls for SO2 [sulfur dioxide] and NOX [nitrogen oxides] … Virtually all coal-fired units have electrostatic precipitators, baghouses, or other advanced controls for high levels of particulate removal.”
[141] Calculated with the dataset: “Power Plant Emissions Trends.” U.S. Environmental Protection Agency. Last updated June 27, 2022. <www.epa.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[142] 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.” Federal Register, November 4, 2010. <www.govinfo.gov>
Pages 68069–68070:
As a result of the Clean Air Act, EPA [U.S. Environmental Protection Agency] 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 [hydrocarbons] and CO [carbon monoxide], and then, in response to EPA’s “Tier 0” standards, with three-way catalysts that also reduced NOX [nitrogen oxides]. 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 [air-to-fuel] 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.
[143] 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.”
[144] Webpage: “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.”
[145] Webpage: “Federal Tax Credits for New All-Electric and Plug-in Hybrid Vehicles.” U.S. Department of Energy and U.S. Environmental Protection Agency. Updated July 7, 2022 at <www.fueleconomy.gov>
“All-electric and plug-in hybrid cars purchased new in or after 2010 may be eligible for a federal income tax credit of up to $7,500. The credit amount will vary based on the capacity of the battery used to power the vehicle. State and/or local incentives may also apply.”
[146] Webpage: “State and Federal Electric Vehicle Funding Programs.” Massachusetts State Government. Accessed June 25, 2021 at <www.mass.gov>
The Department of Energy Resources’ Massachusetts Offers Rebates for Electric Vehicles (MOR-EV) program which had expired on September 30th, 2019, has been re-opened. Starting on January 1, 2020, MOR-EV will be extended to support qualifying battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs) up to a $50,000 final purchase price with a $2,500 rebate. Additionally, plug-in hybrid electric vehicles (PHEVS) with an all-electric range of 25 miles or greater and with a final purchase price up to $50,000 are eligible for a $1,500 rebate.
[147] Press release: “Governor Newsom Announces California Will Phase Out Gasoline-Powered Cars & Drastically Reduce Demand for Fossil Fuel in California’s Fight Against Climate Change.” Office of Governor Gavin Newson, September 23, 2020. <www.gov.ca.gov>
Governor Gavin Newsom today announced that he will aggressively move the state further away from its reliance on climate change-causing fossil fuels while retaining and creating jobs and spurring economic growth—he issued an executive order requiring sales of all new passenger vehicles to be zero-emission by 2035 and additional measures to eliminate harmful emissions from the transportation sector. …
Following the order, the California Air Resources Board will develop regulations to mandate that 100 percent of in-state sales of new passenger cars and trucks are zero-emission by 2035—a target which would achieve more than a 35 percent reduction in greenhouse gas emissions and an 80 percent improvement in oxides of nitrogen emissions from cars statewide. In addition, the Air Resources Board will develop regulations to mandate that all operations of medium- and heavy-duty vehicles shall be 100 percent zero emission by 2045 where feasible, with the mandate going into effect by 2035 for drayage trucks. To ensure needed infrastructure to support zero-emission vehicles, the order requires state agencies, in partnership with the private sector, to accelerate deployment of affordable fueling and charging options. It also requires support of new and used zero-emission vehicle markets to provide broad accessibility to zero-emission vehicles for all Californians.
[148] Webpage: “Zero Emission Vehicles.” Vermont State Department of Environmental Conservation. Accessed June 25, 2021 at <dec.vermont.gov>
Vermont’s Low Emission Vehicle (LEV) program, authorized under section 177 of the Clean Air Act, has been a centerpiece of Vermont’s air quality efforts since 1996. The Zero Emission Vehicle (ZEV) program, which is a technology-forcing component of the LEV program, has been a major contributor to the successful commercialization of hybrid-electric vehicles and ultra-low-emission technologies. To date, 12 states have adopted the ZEV Program (California, Colorado, Connecticut, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, Vermont and Washington).
The ZEV program requires increasing sales of ZEVs over the next decade. The annual sales requirements in state programs are modest at the outset, but increase over time, anticipating that consumer demand will expand as consumers become more familiar with a growing range of continually improving ZEV products. The ZEV program provides manufacturers substantial flexibility through mechanisms such as credit banking and trading, alternative compliance options, cross-state credit pooling, and by allowing manufacturers to develop their preferred compliance strategy using Battery Electric Vehicles (BEVs), Plug-in Hybrid Electric Vehicles (PHEVs), Fuel Cell Electric Vehicles (FCEVs), or some combination. The Vermont Department of Environmental Conservation estimates that by 2025, about 5.4 percent of new vehicles sold in Vermont will be required to be ZEVs.
[149] Paper: “Comparative Life Cycle Assessment of Conventional, Electric and Hybrid Passenger Vehicles in Spain.” By Gonzalo Puig-Samber Naranjo and others. Journal of Cleaner Production, April 1, 2021. <www.sciencedirect.com>
[C]urrent and future energy scenario predictions show that electric vehicles will produce an increase in fine particulate matter formation (26%), human carcinogenic (20%) and non-carcinogenic toxicity (61%), terrestrial ecotoxicity (31%), freshwater ecotoxicity (39%), and marine ecotoxicity (41%) relative to petrol vehicles. …
The scope of this study represents a cradle-to-grave approach, considering five life cycle phases: i) vehicle manufacture, ii) components production and transport, iii) vehicle distribution, iv) use phase and v) end-of-life (see Fig. 1), which are further subdivided to express the results and identify hotspots at a process level. …
The results are given (1) for all the vehicle models in the baseline scenario, including the electric vehicle with battery replacement and (2) for the electric vehicle, in future scenarios (2030 and 2050). LCIA [life cycle impact assessment] results are broken down into various vehicle life cycle phases and emission sources….
… Baseline BEV [battery electric vehicle] impact in terms of fine particulate matter formation is caused in a high proportion (40%) by the electricity generation mix, mainly because of the electricity generation from coal, lignite and to a lesser extent oil. The cradle-to-gate phase always contributes the most, principally because of the steel employed for the glider manufacture. …
… Human toxicity related categories are principally influenced by the disposal of sulfidic tailings generated during copper, nickel and gold extraction. Regarding the human carcinogenic toxicity impact category, steel production also plays a major role, which explains the more intensive cradle-to-gate phase of ICEVs [internal combustion engine vehicles] and HEVs [hybrid electric vehicle]. Still, BEVs show the highest impact for both categories in present and future scenarios. This is due to the high copper demand related to the traction battery manufacturing and the influence of the electricity grid. For all vehicles, the vehicle and battery manufacture are the life cycle hotspots, representing 74–88% of the total impact in the baseline and future scenarios. …
The Monte Carlo test provides the confidence intervals of the results. The results for GWP and Fine particulate matter formation show the lowest deviation from the mean, whereas categories related to human toxicity have the largest uncertainties … linked to the large uncertainty of the emissions of Zn and Cr (VI) into water, which are the major contributors to human carcinogenic and non-carcinogenic toxicity, respectively. Regarding ecotoxicity-related categories, BEVs and HEVs have larger uncertainties than ICEVs because of the higher deviations of the most contributing processes: emissions of Zn into water (i.e. aquatic ecotoxicity categories) and Cu airborne emissions. Generally, the uncertainty analysis of the difference between vehicles and the BEV confirms the conclusions drawn in this study. This difference is considered statistically-significant when at least 95% of the Monte Carlo runs show a clear positive or negative output. …
The results highlight the need for evaluating passenger vehicles from a cradle-to-grave perspective and considering different impact categories. The study underlines that this approach is increasingly required because of both BEV and HEV transfer of environmental burdens to the cradle-to-gate phase and their very high impacts on human health and ecosystems. In this regard, BEVs perform the worst regarding fine particulate matter formation, human toxicity and ecotoxicity in current and future scenarios.
[150] 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 [greenhouse gas]. 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….”
[151] 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….”
[152] Article: “Background and Reflections on the Life Cycle Assessment Harmonization Project.” By Garvin A. Heath and Margaret K. Mann. Journal of Industrial Ecology, April 4, 2012. Pages S8–S11. <onlinelibrary.wiley.com>
Page S8:
Despite the ever-growing body of life cycle assessment (LCA) literature on electricity generation technologies, inconsistent methods and assumptions hamper comparison across studies and pooling of published results. Synthesis of the body of previous research is necessary to generate robust results to assess and compare environmental performance of different energy technologies for the benefit of pol-icy makers, managers, investors, and citizens. …
The LCA Harmonization Project’s initial focus was evaluating life cycle greenhouse gas (GHG) emissions from electricity generation technologies. Six articles from this first phase of the project are presented in a special supplemental issue of the Journal of Industrial Ecology on Meta-Analysis of LCA: coal (Whitaker and others 2012), concentrating solar power (Burkhardt and others 2012), crystalline silicon photovoltaics (PVs) (Hsu and others 2012), thin-film PVs (Kim and others 2012), nuclear (Warner and Heath 2012), and wind (Dolan and Heath2012).
Page S10:
Harmonization is a meta-analytical approach that addresses inconsistency in methods and assumptions of previously published life cycle impact estimates. It has been applied in a rigorous manner to estimates of life cycle GHG emissions from many categories of electricity generation technologies in articles that appear in this special supplemental issue, reducing the variability and clarifying the central tendency of those estimates in ways useful for decision makers and analysts.
[153] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
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.
[154] 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 [greenhouse gas] 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 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 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. …
[155] 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 [photovoltaic] 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 [cadmium telluride] PV amounts to 89–98% reductions of GHG [greenhouse gas] 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.
[156] Paper: “Life Cycle Greenhouse Gas Emissions of Crystalline Silicon Photovoltaic Electricity Generation.” By David D. Hsu and others. Journal of Industrial Ecology, March 19, 2012. Pages 122–135. <onlinelibrary.wiley.com>
Page 2173:
Published scientific literature contains many studies estimating life cycle greenhouse gas (GHG) emissions of residential and utility‐scale solar photovoltaics (PVs). Despite the volume of published work, variability in results hinders generalized conclusions. Most variance between studies can be attributed to differences in methods and assumptions. To clarify the published results for use in decision making and other analyses, we conduct a meta‐analysis of existing studies, harmonizing key performance characteristics to produce more comparable and consistently derived results.
Screening 397 life cycle assessments (LCAs) relevant to PVs yielded 13 studies on crystalline silicon (c‐Si) that met minimum standards of quality, transparency, and relevance. Prior to harmonization, the median of 42 estimates of life cycle GHG emissions from those 13 LCAs was 57 grams carbon dioxide equivalent per kilowatt‐hour (g CO2‐eq/kWh), with an interquartile range (IQR) of 44 to 73. After harmonizing key performance characteristics (irradiation of 1,700 kilowatt‐hours per square meter per year (kWh/m2/yr); system lifetime of 30 years; module efficiency of 13.2% or 14.0%, depending on module type; and a performance ratio of 0.75 or 0.80, depending on installation, the median estimate decreased to 45 and the IQR tightened to 39 to 49. The median estimate and variability were reduced compared to published estimates mainly because of higher average assumptions for irradiation and system lifetime.
[157] Webpage: “Geothermal Energy and the Environment.” U.S. Energy Information Administration. Last updated November 19, 2020. <www.eia.gov>
Geothermal power plants do not burn fuel to generate electricity, but they may release small amounts of sulfur dioxide and carbon dioxide. Geothermal power plants emit 97% less acid rain-causing sulfur compounds and about 99% less carbon dioxide than fossil fuel power plants of similar size. Geothermal power plants use scrubbers to remove the hydrogen sulfide naturally found in geothermal reservoirs. Most geothermal power plants inject the geothermal steam and water that they use back into the earth. This recycling helps to renew the geothermal resource….
[158] 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>
Page 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.
Pages S151–152:
Life cycle GHG 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.
[159] Webpage: “Hydropower Explained: Hydropower and the Environment.” U.S. Energy Information Administration. Last updated December 9, 2021.
Most dams in the United States were built mainly for flood control, municipal water supply, and irrigation water. Although many of these dams have hydroelectric generators, only a small number of dams were built specifically for hydropower generation. Hydropower generators do not directly emit air pollutants. However, dams, reservoirs, and the operation of hydroelectric generators can affect the environment. …
Manufacturing the concrete and steel in hydropower dams requires equipment that may produce emissions. If fossil fuels are the energy sources for making these materials, then the emissions from the equipment could be associated with the electricity that hydropower facilities generate. However, given the long operating lifetime of a hydropower plant (50 years to 100 years) these emissions are offset by the emissions-free hydroelectricity.
Greenhouse gases (GHG) such as carbon dioxide and methane form in natural aquatic systems and in human-made water storage reservoirs as a result of the aerobic and anaerobic decomposition of biomass in the water. The exact amounts of GHG that form in and are emitted from hydropower reservoirs is uncertain and depend on many site specific and regional factors.
[160] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
“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.”
[161] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
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.
[162] Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 255:
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 fixed period of time, such as 100 years.
[163] Report: “Recent Greenhouse Gas Concentrations.” By T.J. Blasing. U.S. Department of Energy, Carbon Dioxide Information Analysis Center. Updated April 2016. <cdiac.ess-dive.lbl.gov>
“GWP4 [global warming potential] (100-yr time horizon) … Carbon dioxide (CO2) [=] 1 … Methane (CH4) [=] 28”
[164] Webpage: “How Much Carbon Dioxide Is Produced When Different Fuels Are Burned?” U.S. Energy Information Administration. Last reviewed May 10, 2022. <www.eia.gov>
Different fuels emit different amounts of carbon dioxide (CO2) 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. …
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 noncombustible elements in some fuels, reduce their heating values and increase their CO2-to-heat contents.
[165] Webpage: “Carbon Dioxide Emissions Coefficients.” U.S. Energy Information Administration. Last reviewed May 10, 2022. <www.eia.gov>
|
Carbon Dioxide Emissions Coefficients by Fuel |
|
|
Carbon Dioxide (CO2) Factors: |
Pounds CO2 Per Million Btu |
|
Propane |
138.63 |
|
Diesel and Home Heating Fuel |
163.45 |
|
Natural Gas |
116.65 |
|
Motor Gasoline |
155.77 |
|
Coal (Anthracite) |
228.60 |
|
Coal (Bituminous) |
205.40 |
|
Coal (Subbituminous) |
214.13 |
|
Coal (Lignite) |
216.24 |
[166] Webpage: “Federal Tax Credits for New All-Electric and Plug-in Hybrid Vehicles.” U.S. Department of Energy and U.S. Environmental Protection Agency. Updated July 7, 2022 at <www.fueleconomy.gov>
“All-electric and plug-in hybrid cars purchased new in or after 2010 may be eligible for a federal income tax credit of up to $7,500. The credit amount will vary based on the capacity of the battery used to power the vehicle. State and/or local incentives may also apply.”
[167] Webpage: “State and Federal Electric Vehicle Funding Programs.” Massachusetts State Government. Accessed June 25, 2021 at <www.mass.gov>
The Department of Energy Resources’ Massachusetts Offers Rebates for Electric Vehicles (MOR-EV) program which had expired on September 30th, 2019, has been re-opened. Starting on January 1, 2020, MOR-EV will be extended to support qualifying battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs) up to a $50,000 final purchase price with a $2,500 rebate. Additionally, plug-in hybrid electric vehicles (PHEVS) with an all-electric range of 25 miles or greater and with a final purchase price up to $50,000 are eligible for a $1,500 rebate.
[168] Press release: “Governor Newsom Announces California Will Phase Out Gasoline-Powered Cars & Drastically Reduce Demand for Fossil Fuel in California’s Fight Against Climate Change.” Office of Governor Gavin Newson, September 23, 2020. <www.gov.ca.gov>
Governor Gavin Newsom today announced that he will aggressively move the state further away from its reliance on climate change-causing fossil fuels while retaining and creating jobs and spurring economic growth—he issued an executive order requiring sales of all new passenger vehicles to be zero-emission by 2035 and additional measures to eliminate harmful emissions from the transportation sector. …
Following the order, the California Air Resources Board will develop regulations to mandate that 100 percent of in-state sales of new passenger cars and trucks are zero-emission by 2035—a target which would achieve more than a 35 percent reduction in greenhouse gas emissions and an 80 percent improvement in oxides of nitrogen emissions from cars statewide. In addition, the Air Resources Board will develop regulations to mandate that all operations of medium- and heavy-duty vehicles shall be 100 percent zero emission by 2045 where feasible, with the mandate going into effect by 2035 for drayage trucks. To ensure needed infrastructure to support zero-emission vehicles, the order requires state agencies, in partnership with the private sector, to accelerate deployment of affordable fueling and charging options. It also requires support of new and used zero-emission vehicle markets to provide broad accessibility to zero-emission vehicles for all Californians.
[169] Webpage: “Zero Emission Vehicles.” Vermont State Department of Environmental Conservation. Accessed June 25, 2021 at <dec.vermont.gov>
Vermont’s Low Emission Vehicle (LEV) program, authorized under section 177 of the Clean Air Act, has been a centerpiece of Vermont’s air quality efforts since 1996. The Zero Emission Vehicle (ZEV) program, which is a technology-forcing component of the LEV program, has been a major contributor to the successful commercialization of hybrid-electric vehicles and ultra-low-emission technologies. To date, 12 states have adopted the ZEV Program (California, Colorado, Connecticut, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, Vermont and Washington).
The ZEV program requires increasing sales of ZEVs over the next decade. The annual sales requirements in state programs are modest at the outset, but increase over time, anticipating that consumer demand will expand as consumers become more familiar with a growing range of continually improving ZEV products. The ZEV program provides manufacturers substantial flexibility through mechanisms such as credit banking and trading, alternative compliance options, cross-state credit pooling, and by allowing manufacturers to develop their preferred compliance strategy using Battery Electric Vehicles (BEVs), Plug-in Hybrid Electric Vehicles (PHEVs), Fuel Cell Electric Vehicles (FCEVs), or some combination. The Vermont Department of Environmental Conservation estimates that by 2025, about 5.4 percent of new vehicles sold in Vermont will be required to be ZEVs.
[170] Paper: “Comparative Life Cycle Assessment of Conventional, Electric and Hybrid Passenger Vehicles in Spain.” By Gonzalo Puig-Samber Naranjo and others. Journal of Cleaner Production, April 1, 2021. <www.sciencedirect.com>
BEVs [battery electric vehicles] and HEVs [hybrid electric vehicles] are generally perceived as a clean alternative and in the case of the former, they are marketed as “zero-emission” because of their null tailpipe emissions. However, the BEV use phase produces environmental impacts through processes that occur in various locations (i.e. power plants). The life cycle approach is needed to avoid problem shifting and evaluate vehicle environmental impacts completely. Only the study of the complete energy carrier, which is known as the Well-to-Wheels (WTW) analysis, enables us to fairly compare the use phase environmental impacts of vehicles with different powertrains. WTW and Life Cycle Assessment (LCA) studies indicate that BEVs only achieve their maximum potential of GHG emissions reduction in electricity grids with a low carbon footprint (Burchart-Korol and others, 2018).
Despite the WTW analysis usefulness to compare the use phase impacts, it is not completely representative of vehicle life cycle environmental impacts since it does not consider other important phases (i.e. production, disposal) and usually only assesses GHG [greenhouse gas] emissions (Folega and Burchart-Korol, 2017). Its limitations are greater for evaluating BEVs and HEVs because these vehicles show higher relative importance of the upstream supply chain and vehicle manufacture. Bauer and others found that BEV and its traction battery production contributes to approximately 55% of the GHG emissions (Bauer and others, 2015). …
The found GWP [global warming potential] for BEVs is considerably lower than the obtained for the other vehicles: Petrol ICEVs (−48%), diesel ICEVs (−44%) and HEVs (−39%), whose values are also within the GWP range established from literature: 258–301 g CO2 eq/km for the petrol and 172–253 g CO2 eq/km for the diesel car…. Regarding the life cycle structure, the results confirm that the vehicle use is the most contributing life cycle phase in terms of GWP. … The reduction of BEV use phase GWP in future scenarios also reveals the progressive transfer of environmental burdens in terms of GHG emissions from the electricity consumption to the cradle-to-gate phase. The contribution of BEV cradle-to-gate phase (i.e. vehicle and traction battery manufacture) to the life cycle GWP increases from 42% to more than 50% in 2030 and 2050.
In this sense, BEVs and HEVs have the most polluting cradle-to-gate phase in terms of GWP. While in the case of HEVs this is due to the production of two different powertrains, BEV manufacture is more intensive mainly because of the battery production, which constitutes approximately 8.5% of the vehicle life cycle GWP. … However, BEVs are capable of rapidly recovering their more intensive manufacturing phase and equalising petrol ICEV total GHG emissions after 6,906 km…. The break-even distance between BEVs and petrol ICEVs rises to 13,353 km if a battery replacement is needed.
The Monte Carlo test provides the confidence intervals of the results. The results for GWP and Fine particulate matter formation show the lowest deviation from the mean, whereas categories related to human toxicity have the largest uncertainties…. This difference is considered statistically-significant when at least 95% of the Monte Carlo runs show a clear positive or negative output. …
… The results regarding future scenarios for BEVs also indicate an important transfer of GHG emissions to the vehicle cradle-to-gate phase, meaning that globally LCA results might be used to plan new eco-design strategies such as a longer lifetime of vehicles, substitution of some hotspot materials and processes, and higher use of secondary materials. In terms of GWP, BEVs are capable of reducing 48% of petrol ICEV GHG emissions in the current Spanish scenario. Future scenarios results underline that BEV promotion must be accompanied by a massive introduction of renewable energies in order to achieve their maximum benefits in terms of GHG emissions. Following the European prospective for Spain, BEVs could potentially reduce 27% of their current GWP by 2050. The use of BEVs in countries or regions with a fossil fuel-based electricity generation completely erases their benefits and could be counterproductive (Burchart-Korol and others, 2018).
[171] Webpage: “Ethanol and the Environment.” U.S. Energy Information Administration. Last updated December 7, 2020. <bit.ly>
Producing and burning ethanol results in emissions of carbon dioxide (CO2), a greenhouse gas. However, the combustion of ethanol made from biomass (such as corn and sugarcane) is considered atmospheric carbon neutral because as the biomass grows, it absorbs CO2, which may offset the CO2 produced when the ethanol is burned. Some ethanol producers burn coal and natural gas for heat sources in the fermentation process to make fuel ethanol, while some burn corn stocks or sugar cane stocks.
The effect that increased ethanol use has on net CO2 emissions depends on how ethanol is made and whether or not indirect impacts on land use are included in the calculations. Growing plants for fuel is a controversial topic because some people believe the land, fertilizers, and energy used to grow biofuel crops should be used to grow food crops instead.
[172] Webpage: “Air Emissions.” U.S. Environmental Protection Agency. Last updated September 25, 2013. <www.justfacts.com>
“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.”
[173] 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.
[174] 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.)”
[175] 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>
Page 5285:
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) [particulate matter].
[176] 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.
[177] Webpage: “Biofuels Explained: Biofuels and the Environment.” U.S. Energy Information Administration. Last reviewed April 13, 2022. <www.eia.gov>
“The U.S. government is supporting efforts to produce biofuels with methods that use less energy than conventional fermentation and that use cellulosic biomass, which requires less cultivation, fertilizer, and pesticides than corn or sugar cane. Cellulosic ethanol feedstock includes native prairie grasses, fast-growing trees, sawdust, and even waste paper.”
[178] 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.
[179] Webpage: “Ethanol Production and Distribution.” U.S. Department of Energy, Alternative Fuels Data Center. Accessed August 3, 2022. <www.afdc.energy.gov>
Making ethanol from cellulosic feedstocks—such as grass, wood, and crop residues—is a more involved process 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..
[180] Report: “The Impact of Ethanol Use on Food Prices and Greenhouse-Gas Emissions.” Congressional Budget Office, April 2009. <www.cbo.gov>
Page 10 (of PDF): “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 [Energy Independence and Security Act of 2007] mandate, greenhouse-gas emissions might be reduced by about 130 million metric tons of CO2e [carbon dioxide equivalent] 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 [U.S. Energy Information Administration] 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
[181] 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.
[182] Ruling: American Petroleum Institute v. Environmental Protection Agency. U.S. 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 [U.S. Environmental Protection Agency] 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 [American Petroleum Institute’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.
[183] See the section on biofuels for the latest details about producers’ inability to make enough cellulosic ethanol to meet the mandated amounts specified in federal law.
[184] 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.
[185] Webpage: “Biomass-Based Diesel and the Environment.” U.S. Energy Information Administration. Last reviewed December 10, 2020. <bit.ly>
Compared to petroleum diesel fuel, which is refined from crude oil, biodiesel combustion produces fewer air pollutants such as particulates, carbon monoxide, sulfur dioxide, hydrocarbons, and air toxics. Nitrogen oxide emissions from burning a gallon of biodiesel may be slightly higher than emissions from burning a gallon of petroleum diesel.
Biodiesel Use May Reduce Greenhouse Gas Emissions
The U.S. government considers biodiesel to be carbon-neutral because the plants that are the sources of the feedstocks for making biodiesel, such as soybeans and palm oil trees, absorb carbon dioxide (CO2) as they grow. The absorption of CO2 by these plants offsets the CO2 that forms while making and burning biodiesel. Most of the biodiesel produced in the United States is made from soybean oil. Some biodiesel is also produced from used vegetable oils or animal fats, including recycled restaurant oil and 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 effects of this land clearing and burning may be greater than the potential benefits of using biodiesel produced from soybeans and palm oil trees.
[186] 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.
[187] 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.”
[188] Report: “A Primer on Alternative Transportation Fuels.” By Timothy Coffey. National Defense University, Center for Technology and National Security Policy, September 2010. <apps.dtic.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)
[189] 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 [a mixture of 70–85% ethanol and 15–30% gasoline] results in an approximately 25 percent reduction in fuel economy.”
[190] “Clean Cities Alternative Fuel Price Report.” U.S. Department of Energy, August 1, 2013. <www.afdc.energy.gov>
Page 7: “Ethanol (E85) [a mixture of 70–85% ethanol and 15–30% gasoline] 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.”
[191] 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.”
[192] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 162: “Table 9.4 Retail Motor Gasoline and On-Highway Diesel Fuel Prices … Prices are not adjusted for inflation.”
b) “Clean Cities Alternative Fuel Price Report, January 2021.” U.S. Department of Energy, April 26, 2021.
Page 3: “This report’s prices represent retail, at-the-pump sales prices for each fuel, including federal and state motor fuel taxes.1 … Some states charge a flat annual fee in lieu of collecting motor fuel taxes at the pump, usually for large trucks using gaseous fuels like compressed natural gas (CNG) and liquefied petroleum gas (LPG or propane). These flat fees are not included in the prices reported in these pages.”
Page 4: “Table 3. National Average Retail Fuel Prices on an Energy‐Equivalent Basis, January 2021”
c) “Clean Cities Alternative Fuel Price Report, April 2021.” U.S. Department of Energy, July 6, 2021.
Page 4: “National Average Retail Fuel Prices on an Energy‐Equivalent Basis, April 2021”
d) “Clean Cities Alternative Fuel Price Report, July 2021.” U.S. Department of Energy, October 26, 2021.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, July 2021”
e) “Clean Cities Alternative Fuel Price Report, October 2021.” U.S. Department of Energy, December 15, 2021.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, October 2021”
NOTE: An Excel file containing the data and calculations is available upon request.
[193] 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.
[194] Article: “Intricacies of Meeting the Renewable Fuels Standard.” By Bruce A. Babcock. Iowa State University Center for Agricultural and Rural Development Iowa Ag Review, Spring 2009. <www.card.iastate.edu>
Gasoline producers and importers are assigned a number of RINs [Renewable Identification Numbers] that they must give to EPA [U.S. Environmental Protection Agency] 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.
[195] Article: “Ethanol and Biomass-Based Diesel RIN Prices Approaching All-Time Highs.” By Sean Hill. U.S. Energy Information Administration, February 24, 2021. <www.eia.gov>
Although the RFS [Renewable Fuel Standard] renewable volume obligations for 2021 have yet to be released, RIN [Renewable Identification Numbers] prices have been increasing because of limited fuel production as a result of lower fuel demand related to responses to COVID-19, fewer approved new small refinery exemptions (SRE) since 2018, and uncertainty around future RFS levels.
In the past, RIN credit prices increased, generally, because of two situations: when the cost of a biofuel was higher than the petroleum fuel it was blended into or when RFS targets increased more than market-driven biofuel consumption. In the second situation, the higher-value RINs encourage additional, more costly blending beyond normal market levels.
The recent price increase is likely attributable to the first situation. In spring 2020, as transportation demand was quickly falling, wholesale gasoline prices fell by more than wholesale ethanol prices, causing ethanol D6 RIN prices to increase enough to encourage increased ethanol blending. Similarly, diesel fuel prices fell significantly lower than biomass-based diesel (both biodiesel and renewable diesel), driving biomass-based diesel D4 RIN prices higher to encourage blending costlier biofuels.
[196] 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 [Renewable Identification Numbers] 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 [U.S. Environmental Protection Agency] 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 [Renewable Fuel Standard] 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.
[197] 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 [Renewable Identification Number] 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 [Renewable Fuel Standard, Energy Independence and Security Act of 2007] 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.”
[198] Webpage: “Biodiesel Income Tax Credit.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center. Accessed August 6, 2022 at <afdc.energy.gov>
Biodiesel Income Tax Credit
NOTE: This incentive originally expired on December 31, 2017, but was retroactively extended through December 31, 2022, by Public Law 116-94.
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.
[199] Calculated with data from:
a) Report: “Direct Federal Financial Interventions and Subsidies in Energy in Fiscal Year 2016.” U.S. Energy Information Administration, April 2018. <www.eia.gov>
Page 9: “Table 3. Quantified Energy-Specific Subsidies and Support by Type, FY 2010, FY 2013 and FY 2016 (million 2016 dollars) … Year and Support Type … 2016 … Natural Gas and Petroleum Liquids … Direct Expenditures [=] 111 … Tax Expenditures [=] (940) … Research and Development [=] 56 … DOE [U.S. Department of Energy] Loan Guarantee Program [=] 0”
Page 25: “Natural gas and petroleum-related U.S. tax expenditures decreased from $2.3 billion in FY 2013 to an estimated revenue inflow (versus a positive tax expenditure) of $940 million in FY 2016 thus in aggregate becoming a set of revenue-generating tax provisions to the government in that fiscal year….”
b) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 5: “Table 1.2: Primary Energy Production by Source (Quadrillion BTU) … 2016 … Natural Gas (Dry) [=] 27.576 … Crude Oil [=] 18.522 … NGPL [Natural Gas Plant Liquids] [=] 4.665”
c) Dataset: “Fuel Properties Comparison.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center, January 2021. <www.afdc.energy.gov>
Page 1: “Energy Content (Higher heating value) … Gasoline [=] 120,388–124,340 Btu/gal”
NOTES:
[200] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 162: “Table 9.4 Retail Motor Gasoline and On-Highway Diesel Fuel Prices … Prices are not adjusted for inflation.”
b) “Clean Cities Alternative Fuel Price Report, January 2021.” U.S. Department of Energy, April 26, 2021.
Page 3: “This report’s prices represent retail, at-the-pump sales prices for each fuel, including federal and state motor fuel taxes.1 … Some states charge a flat annual fee in lieu of collecting motor fuel taxes at the pump, usually for large trucks using gaseous fuels like compressed natural gas (CNG) and liquefied petroleum gas (LPG or propane). These flat fees are not included in the prices reported in these pages.”
Page 4: “Table 3. National Average Retail Fuel Prices on an Energy‐Equivalent Basis, January 2021”
c) “Clean Cities Alternative Fuel Price Report, April 2021.” U.S. Department of Energy, July 6, 2021.
Page 4: “National Average Retail Fuel Prices on an Energy‐Equivalent Basis, April 2021”
d) “Clean Cities Alternative Fuel Price Report, July 2021.” U.S. Department of Energy, October 26, 2021.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, July 2021”
e) “Clean Cities Alternative Fuel Price Report, October 2021.” U.S. Department of Energy, December 15, 2021.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, October 2021”
f) Dataset: “RIN Price Report, 2021.” U.S. Environmental Protection Agency. Last updated July 25, 2022. <www.epa.gov>
g) Dataset: “RIN Transaction Volumes, 2021.” U.S. Environmental Protection Agency. Last updated July 25, 2022. <www.epa.gov>
h) 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).”
i) “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.”
j) Report: “A Primer on Alternative Transportation Fuels.” By Timothy Coffey. National Defense University, Center for Technology and National Security Policy, September 2010. <apps.dtic.mil>
Page 25: “Table 6. Energy content and chemical composition of several energy sources referenced to gasoline. … Energy per unit volume … Liquid Ethanol [=] .69”
k) Webpage: “Biodiesel Income Tax Credit.” U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Alternative Fuels Data Center. Accessed August 6, 2022 at <www.afdc.energy.gov>
“Biodiesel Income Tax Credit … NOTE: This incentive originally expired on December 31, 2017, but was retroactively extended through December 31, 2022, by Public Law 116-94. … 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.”
NOTE: An Excel file containing the data and calculations is available upon request.
[201] Renewable Fuel Standard (RFS) subsidies for biodiesel and ethanol are measured by the cost of the credits petroleum companies use “to demonstrate compliance with the standard.” The credits—called RINs [Renewable Identification Numbers]—represent each gallon of renewable fuel produced. Companies that produce renewable fuels are issued RINs, which petroleum companies buy and submit to the U.S. Environmental Protection Agency.†
Just Facts uses the records from the EPA’s RIN transaction system to calculate the weighted average RIN price for each fuel. This data has the following caveats and limitations:
NOTES:
[202] Article: “Scientific Survey Shows Voters Widely Accept Misinformation Spread By the Media.” By James D. Agresti. Just Facts, January 2, 2020. <www.justfacts.com>
The findings are from a nationally representative annual survey commissioned by Just Facts, a non-profit research and educational institute. The survey was conducted by Triton Polling & Research, an academic research firm that used sound methodologies to assess U.S. residents who regularly vote. …
The survey was conducted by Triton Polling & Research, an academic research firm that serves scholars, corporations, and political campaigns. The responses were obtained through live telephone surveys of 700 likely voters across the U.S. during December 2–11, 2019. This sample size is large enough to accurately represent the U.S. population. Likely voters are people who say they vote “every time there is an opportunity” or in “most” elections.
The margin of sampling error for the total pool of respondents is ±4% with at least 95% confidence. The margins of error for the subsets are 6% for Democrat voters, 6% for Trump voters, 5% for males, 5% for females, 12% for 18 to 34 year olds, 5% for 35 to 64 year olds, and 6% for 65+ year olds.
The survey results presented in this article are slightly weighted to match the ages and genders of likely voters. The political parties and geographic locations of the survey respondents almost precisely match the population of likely voters. Thus, there is no need for weighting based upon these variables.
NOTE: For facts about what constitutes a scientific survey and the factors that impact their accuracy, visit Just Facts’ research on Deconstructing Polls & Surveys.
[203] Calculated with the dataset: “Just Facts’ 2019 U.S. Nationwide Survey.” Just Facts, January 2020. <www.justfacts.com>
Page 4:
Q17. Without government subsidies, which of these fuels do you believe is least expensive for powering automobiles?
Gasoline [=] 46.3%
Ethanol [=] 14.1%
Biodiesel [=] 25.7%
Unsure [=] 13.4%
Refused [=] 0.4%
CALCULATION: 14.1% ethanol + 25.7% biodiesel = 39.8%
[204] For facts about how surveys work and why some are accurate while others are not, click here.
[205] Calculated with data from:
a) Report: “June 2020 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, June 25, 2020. <www.eia.gov>
Page 160: “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 2019.” U.S. Department of Energy, March 14, 2019.
Page 3: “This report’s prices represent retail, at-the-pump sales prices for each fuel, including federal and state motor fuel taxes. … Some states charge a flat annual fee, in lieu of collecting motor fuel taxes at the pump, usually for large trucks using gaseous fuels like compressed natural gas (CNG) and liquefied petroleum gas (LPG or propane). These flat fees are not included in the prices reported in these pages.”
Page 4: “Table 3. National Average Retail Fuel Prices on an Energy‐Equivalent Basis, January 2019”
c) “Clean Cities Alternative Fuel Price Report, April 2019.” U.S. Department of Energy, May 30, 2019.
Page 4: “National Average Retail Fuel Prices on an Energy‐Equivalent Basis, April 2019”
d) “Clean Cities Alternative Fuel Price Report, July 2019.” U.S. Department of Energy, October 8, 2019.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, July 2019”
e) “Clean Cities Alternative Fuel Price Report, October 2019.” U.S. Department of Energy, December 18, 2019.
Page 4: “Table 3. National Average Fuel Prices on An Energy-Equivalent Basis, October 2019”
f) Email from the Department of Agricultural and Consumer Economics at the University of Illinois at Urbana-Champaign to Just Facts, July 15, 2020.
“2019 national average RINs prices … D6 [ethanol] = $0.18 … D4 [biodiesel] = $0.47”
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. <apps.dtic.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 May 5, 2020 at <afdc.energy.gov>
“Biodiesel Income Tax Credit … NOTE: This incentive originally expired on December 31, 2016, but was retroactively extended through December 31, 2022, by Public Law 116-94. … 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.”
NOTE: An Excel file containing the data and calculations is available upon request.
[206] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <www.ferc.gov>
Page 36:
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 [kilowatt hour] 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.
[207] For rates after 2015, see the forthcoming chart of inflation-adjusted average prices of electricity in the United States.
[208] Calculated with data from:
a) Dataset: “Average Price by State by Provider, 1990–2020.” U.S. Energy Information Administration, April 15, 2022. <www.eia.gov>
b) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed February 5, 2022 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[209] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.justfacts.com>
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).
[210] 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.”
[211] 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. <eta-publications.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.
[212] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.justfacts.com>
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.
[213] Webpage: “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.
[214] 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. <eta-publications.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).”
[215] 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.”
[216] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.justfacts.com>
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
[217] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
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. 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.
[218] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <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.
[219] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
“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.”
[220] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[221] 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.”
[222] 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.
[223] 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.”
[224] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[225] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee/Northwest Natural Gas Association Planning Task Force, August 2012. <docplayer.net>
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).
[226] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 [Annual Energy Outlook] 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 [greenhouse gas] legislation also dampen interest in new coal-fired capacity82. 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 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.
[227] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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. 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. … 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 emissions is in place, which makes investment in new coal-fired capacity unlikely.
NOTE: The next footnote documents that natural gas is currently about 2.5 times the price of coal, which is higher than the breakeven point for being competitive with coal in generating baseload power.
[228] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 169: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”
NOTES:
[229] Article: “Natural Gas-Fired Power Plants Are Being Added and Used More in PJM Interconnection.” U.S. Energy Information Administration, October 17, 2018. <www.eia.gov>
Higher capacity factors for natural gas-fired combined-cycle generators in recent years also indicate a fundamental shift in day-to-day operations of these power plants. Natural gas-fired generators were traditionally used as either intermediate load following (cycling) or peaking resources. In recent years, however, combined-cycle power plants have become more competitive with coal-fired plants for baseload operations and have led to increasing retirements of coal plants.
[230] Article: “U.S. Natural Gas Consumption Sets New Record in 2019.” U.S. Energy Information Administration, March 3, 2020. <www.eia.gov>
Natural gas continues to account for the largest share of electricity generation after first surpassing coal-fired generation on an annual basis in 2016. In 2019, natural gas accounted for 38% of total electricity generation, followed by 23% for coal and 20% for nuclear. New natural gas generation capacity additions have continued to displace coal-fired power plants; about 5% of the total existing U.S. coal-fired capacity was retired in 2019. …
The electric power sector has been shifting toward natural gas in the past decade because of competitive natural gas prices and power plant technology improvements.
[231] Article: “More Power Generation Came From Natural Gas in First Half of 2020 Than First Half of 2019.” By Stephen York and Mark Morey. U.S. Energy Information Administration, August 12, 2020. <www.eia.gov>
Natural gas-fired generation in the Lower 48 states increased nearly 55,000 gigawatthours (GWh), or 9%, in the first half of 2020 compared with the first half of 2019. …
Coal-fired generation absorbed most of the decrease in electrical load in the first half of 2020, registering a 138,000 GWh (30%) decline in output. Because of historically low natural gas prices so far in 2020, coal-fired generation this year has been uneconomical in most regions compared with natural gas-fired generation, leading to price-driven coal-to-natural gas fuel switching. …
Coal-to-natural gas switching was most prominent in the PJM Interconnection (PJM), which covers an area stretching from New Jersey to Illinois, and the Midcontinent Independent System Operator (MISO), which primarily includes areas in the Midwest. PJM and MISO together account for about 35% of the total Lower 48 states’ electric power generation. In both interconnections, competition exists between natural gas and coal as generation fuels, so relative shifts in fuel prices can influence the type of power plant that is dispatched.
… In addition, coal-fired generation remains reasonably competitive in ERCOT [Electric Reliability Council of Texas] because power plants have access to low-cost subbituminous coal from Wyoming’s Powder River Basin and to lignite—the lowest quality of coal—produced at mines near several plants.
Capacity additions have also contributed to the growth in natural gas-fired generation. According to the Electric Power Monthly, about 18,000 megawatts (MW) of net capacity from new combined-cycle natural gas turbine plants has entered service since 2018. Output from these highly efficient plants has been steadily ramping up and helping to drive increases in generation.
[232] 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. <fire.pppl.gov>
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.
[233] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[234] Booklet: “What You Need to Know About Energy.” National Academy of Sciences, 2008. <nap.nationalacademies.org>
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. Similar technologies are being developed for use in coal power plants.
[235] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 169: “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.
[236] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 169:“Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btu, Including Taxes)”
b) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed February 5, 2022 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[237] 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. <fire.pppl.gov>
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.”
[238] 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.
[239] 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.”
[240] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <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 [Federal Energy Regulatory Commission] 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, market 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.”
[241] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 [Annual Energy Outlook] 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.
[242] Report: “Investment Decisions for Baseload Power Plants.” Prepared by ICF International for the National Energy Technology Laboratory, January 29, 2010. <citeseerx.ist.psu.edu>
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….”
[243] 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.
[244] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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. …
[I]n the AEO2013 [Annual Energy Outlook] 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.
[245] 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.”
[246] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <www.ferc.gov>
Page 38: “Electric power is one of the most capital intensive industries.”
[247] Report: “Natural Gas-Electricity Primer.” By Randy Friedman and others. Pacific Northwest Utilities Conference Committee / Northwest Natural Gas Association Planning Task Force, August 2012. <docplayer.net>
Page 12: “However, electricity supply and demand must be balanced on a real-time basis in very short intervals (measured in seconds).”
[248] 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.
[249] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[250] 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.”
[251] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <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.”
[252] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.”
[253] 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. <fire.pppl.gov>
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.”
[254] 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.
[255] 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.
[256] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.”
[257] 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 [U.S. Energy Information Administration], the direct comparison of LCOE across technologies to determine the economic competitiveness of various generation alternatives is problematic and potentially misleading.
[258] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.”
[259] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.”
[260] 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.”
[261] 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.”
[262] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.com>
Page 1: “Costs are estimated using tax depreciation schedules consistent with current law, which vary by technology.”
[263] 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.
[264] 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. <www.bls.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[265] Email from Just Facts to the U.S. Energy Information Administration on June 11, 2013:
In AEO [Annual Energy Outlook] 2010, the estimated levelized cost of new generation wind capacity in 2016 was 149.3 (2008 $/megawatthour). Contrastingly, in AEO 2013, the estimated levelized cost of new generation wind capacity in 2018 is 86.6 (2011 $/megawatthour). After adjusting for inflation, this amounts to a 44% decrease. What are the specific causes of this differential? Has the technology changed dramatically, or is this change driven by other factors?
Email from the U.S. Energy Information Administration to Just Facts on June 11, 2013:
The levelized costs, especially for wind, are the result of a number of different factors, many of which contribute to its variation over time. Often times, these changes work in opposite directions, and the net impact on levelized cost when compared across AEO volumes may not necessarily be intuitively obvious. For example, between AEO 2010 and AEO 2013, our estimated base capital cost for onshore wind capacity increased from $1966/kW (in 2008$) to $2,212/kW (in 2011$). However, between these two estimates, a number of other factors in the estimate changed. For example, our 2015 estimate for utility-grade bond interest rates went from 7.2% to 6.2%. The cost of debt contributes significantly to the levelized cost calculation for a capital-intensive technology like wind.
Another significant factor contributing to the difference between the two estimates relates to our modeling of the “supply curve” for windy lands. In general, we assume that the best wind sites will be built-out first, and that windy lands will become incrementally more expensive to exploit as lower-quality (lower wind speeds, further from transmission, more community opposition, etc.) sites need to be utilized for new builds. For AEO 2011, we significantly changed how we represented this in the model, providing better resolution of both the regional geography and the supply curve itself (note, the numbers you cite are averages across several regions, and are strongly affected by the characteristics of the best and worst regions). As a result of these changes, there are fewer regions contributing to the average with very high costs, and hence lower averages.
Finally, we have updated our estimates of capacity factors for wind. In general, we find that the performance of newer wind plants is improving at a rate that is somewhat better than we had assumed in 2010. Higher capacity factors result in lower levelized costs (since levelized cost is essentially annualized costs divided by annual generation, where annual generation is capacity factor*capacity*hours in a year).
I have not attempted to analyze the exact contribution of these various factors to the change in levelized cost that you note, but I believe I have captured the primary constituents of the change. However, it is possible that there are other factors at work.
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 (actually, this is something else that has changed since AEO 2010 … used to be 20 years; the longer financial life would also tend to decrease the levelized cost). This means that an investor would expect to recover his investment over a 30-year period. Our assumptions for operation and maintenance expenses account for the cost of maintaining the facility during the assumed financial life. In general, the electric power industry has shown a significant ability to extend the life of most plants well beyond a 30-year cost recovery period (there are many examples of hydro, coal, and nuclear plants that have operated well over 30 years, although I do not know the averages for any of these…. There are also a few wind plants that have operated for as much as 30 years, although the overwhelming majority of wind and solar capacity has been installed in the past few years, so it is hard to get a good estimate of an “expected” life span for these units (similarly, much of the natural gas build-out occurred in the past 20-years, so it would be hard to estimate life span for that).
As indicated above, the capacity factor is a major component in the equation for calculating levelized cost.
[266] 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.justfacts.com>
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.
[267] 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 [levelized costs of electricity] 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.
[268] Calculated with data from:
a) Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2017.” U.S. Energy Information Administration, April 2017. <www.eia.gov>
Page 8: “Table 1b. Estimated Levelized Cost of Electricity (capacity-weighted average1) for New Generation Resources Entering Service in 2022 (2016 $/MWh)”
b) Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019.” U.S. Energy Information Administration, February 2019. <www.eia.gov>
Page 7: “Table 1b. Estimated Levelized Cost of Electricity (Unweighted Average) for New Generation Resources Entering Service in 2023 (2018 $/Mwh))”
c) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed February 15, 2020 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[269] Email from the U.S. Energy Information Administration to Just Facts on June 15, 2018:
Most of the cost declines in AEO2018 [Annual Energy Outlook] relative to AEO2017 projected LCOE [levelized costs of electricity] are the result of a change in the weighted average cost of capital (WACC) assumption used in the LCOE calculation. The WACC represents the rate-of-return needed on the sale of the electricity in order to pay interest on project development loans (cost of debt) and ensure a competitive return on investment for project owners (cost of equity). While the WACC components (cost of debt and cost of equity) are determined in the macroeconomic module of our energy modeling system, we did change a key assumption in our LCOE calculation between AEO20017 and 2018 that is probably magnifying any changes in underlying interest rates or equity markets.
Specifically, for AEO2017 and prior outlooks, we assumed that the cost of debt accounted for 45% of the total WACC (cost of equity the remaining 55%). However, based on a study we did during 2017, we determined that the typical capital structure used in the electric power industry had moved to be more debt-weighted. Therefore, starting in AEO2018, we now assume that the debt component of WACC is 60%. Note that in the early years of the projection (AEO2018 only), the equity component for wind and solar is a bit higher than it is for other technologies because of the impact of the expiring Federal tax credits on financing considerations for these technologies. In general, this reduced the WACC by about 20%, from about 5.5% in AEO2017 to about 4.5% in AEO2018 (WACC varies by projection year, and will be somewhat higher for wind and solar when receiving the tax credit).
[270] In these same projections, EIA [U.S. Energy Information Administration] increased the capacity factor (rate of actual output to potential output) for PV [photovoltaic] solar by 32%. When asked why, EIA responded:
For PV in particular, we did a significant update of our projection methodology to better account for intra-regional variation in solar output. Therefore, we have higher available capacity factors for PV in most regions (reflecting that we are no longer using simple averages across large geographic footprint regions, but allowing projects to be built in better places in each region first). We have had a similar construct in place for our wind model for some time, which results in modest changes in wind capacity factors from scenario to scenario and outlook to outlook. [Email from the U.S. Energy Information Administration to Just Facts on June 15, 2018.]
[271] Calculated with data from:
b) Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2020.” U.S. Energy Information Administration, February 2020. <www.eia.gov>
Page 7: “Table 1b. Estimated Levelized Cost of Electricity (LCOE, unweighted) for New Generation Resources Entering Service in 2025 (2019 Dollars Per Megawatthour)”
a) Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2019.” U.S. Energy Information Administration, February 2019. <www.eia.gov>
Page 7: “Table 1b. Estimated Levelized Cost of Electricity (LCOE, unweighted) for New Generation Resources Entering Service in 2025 (2019 Dollars Per Megawatthour)”
c) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed March 5, 2021 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[272] Email from Just Facts to the U.S. Energy Information Administration on February 19, 2016:
“Are LCOE [levelized costs of electricity] 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.
[273] Email from Just Facts to the U.S. Energy Information Administration on August 13, 2013:
Does EIA [U.S. Energy Information Administration] 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 [National Energy Modeling System] 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.
[274] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.
[275] “Kansas Energy Report 2009.” Kansas Energy Council, January 7, 2009. <www.justfacts.com>
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.
[276] 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.
[277] Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2022.” U.S. Energy Information Administration, February 2021. <www.eia.gov>
Page 6: “We calculate all levelized costs and values based on a 30-year cost recovery period, using a nominal after-tax weighted average cost of capital (WACC) of 6.2%.8 In reality, a plant’s cost recovery period and cost of capital can vary by technology and project type.”
[278] 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.”
[279] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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.”
[280] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 challenges90, 91. Typical challenges involve degradation of structural materials, maintaining safety margins, and assessing the structural integrity of concrete92.
The outcome of pending research and market developments will be important to future decisions regarding life extensions beyond 60 years. The AEO2013 [Annual Energy Outlook] 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.”
[281] 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.”
[282] 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.”
[283] Report: “Distributed Generation System Characteristics and Costs in the Buildings Sector.” Prepared by ICF International for the U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting, August 2013. <www.eia.gov>
Page vi:
Lifetime. Crystalline PV [photovoltaic] 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.
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.
[284] 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.”
[285] 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.”
[286] Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:
EIA [U.S. Energy Information Administration] 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 [photovoltaic] 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).
[287] “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 [photovoltaic] 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.
[288] 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 [photovoltaic] 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.
[289] 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 3:
In the AEO2015 [Annual Energy Outlook] 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…. 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 [levelized cost of electricity] values for coal-fired plants without CCS [carbon control and sequestration] are higher than would otherwise be expected.
[290] Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019.” U.S. Energy Information Administration, February 2019. <www.eia.gov>
Pages 5–6:
EIA [U.S. Energy Information Administration] calculates LCOE [levelized cost of electricity] values based on a 30-year cost recovery period, using a real after-tax weighted average cost of capital (WACC) of 4.2%.7 In reality, a plant’s cost recovery period and cost of capital can vary by technology and project type. In the AEO2019 [Annual Energy Outlook] Reference case, EIA includes a three-percentage-point increase to the cost of capital when evaluating investments for new coal-fired power plants and new coal-to-liquids (CTL) plants without carbon capture and sequestration (CCS) and pollution control retrofits. This increase reflects observed financial risks8 associated with major investments in long operating-life power plants with a relatively higher rate of carbon dioxide (CO2) emissions. AEO2019 takes into account two coal-fired technologies that are compliant with the New Source Performance Standard (NSPS) for CO2 emissions under Section 111(b) of the Clean Air Act. One technology is designed to capture 30% of CO2 emissions and would still be considered a high emitter relative to other new sources; therefore, it may continue to face potential financial risk if CO2 emission controls are further strengthened. Another technology is designed to capture 90% of CO2 emissions and would not face the same financial risk; therefore, EIA does not assume the three-percentage-point increase in the cost of capital. As a result, the LCOE values for a coal-fired plant with 30% CCS are higher than they would be if the same cost of capital were used for all technologies.
7 The real WACC of 4.2% corresponds to a nominal after-tax rate of 7.0% for plants entering service in 2023. For plants entering service in 2021 and 2040, the nominal WACC used to calculate LCOE was 6.8% and 7.0%, respectively. An overview of the WACC assumptions and methodology can be found in the Electricity Market Module of the National Energy Modeling System: Model Documentation 2018 (<www.eia.gov>).
8 See, for example, “Companies End Effort to Buy Navajo Generating Station”, Power, September 21, 2018 for an example of both financing and off-take risks facing coal-fired capacity or “One of U.K.’s largest banks won’t fund new plants or mines,” ClimateWire (subscription required), August 3, 2018 for an example of increasingly limited options in international finance markets for such plants.
[291] Calculated with data from:
a) 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 6: “Table 1. Estimated levelized cost of electricity (LCOE) for new generation resources, 2020”
b) “Loan Calculator and Amortization.” Bankrate. Accessed October 9, 2013 at <www.bankrate.com>
NOTES:
[292] Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2021.” U.S. Energy Information Administration, February 2021. <www.eia.gov>
Page 6:
Starting in AEO [Annual Energy Outlook] 2020, EIA represents an ultra-supercritical9 (USC) coal generation technology without carbon capture and sequestration (CCS). In December 2018, the U.S. Environmental Protection Agency (EPA) amended earlier 2015 findings that partial CCS was the best system of emissions reductions (BSER) for greenhouse gas reductions and proposed to replace it with the most efficient demonstrated steam cycle, which EIA assumes is represented by ultra-supercritical coal technology. Regulatory or court actions related to power plant emissions taken after September 2020 are not accounted for in AEO2021.
9 USC coal plants are compatible with CCS technologies because they use boilers that heat coal to higher temperatures, which increases the pressure of steam to improve efficiency and results in less coal use and fewer carbon emissions than other boiler technologies.
[293] Calculated with data from:
a) Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2022.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Page 6:
Starting in AEO2020[Annual Energy Outlook], we model an ultrasupercritical10 (USC) coal generation technology without carbon capture and sequestration (CCS), and we continue to model USC with 30% and 90% CCS. In December 2018, the U.S. Environmental Protection Agency (EPA) amended earlier 2015 findings that partial CCS was the best system of emissions reductions (BSER) for greenhouse gas reductions and proposed to replace it with the most efficient demonstrated steam cycle, which we assume is represented by USC technology. …
10 USC coal plants are compatible with CCS technologies because they use boilers that heat coal to higher temperatures, which increases the pressure of steam to improve efficiency and results in less coal use and fewer carbon emissions than other boiler technologies.
Page 9: “Table 1b. Estimated Unweighted Levelized Cost of Electricity (LCOE) and Levelized Cost of Storage for New Resources Entering Service in 2027 (2021 Dollars Per Megawatthour)”
Page 13: “Table 4b. Value-Cost Ratio (Unweighted) for New Resources Entering Service in 2027”
NOTE: An Excel file containing the data and calculations is available upon request.
[294] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.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 [U.S. Energy Information Administration] long-term projections reflect these concepts rather than simple comparisons of levelized project costs across technologies.
[295] 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.
[296] Email from Just Facts to the U.S. Energy Information Administration on June 12, 2013:
The EIA [U.S. Energy Information Administration] 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.
[297] 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 [photovoltaic], 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 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 [U.S. Energy Information Administration] 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.”
[298] 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.”
[299] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[300] 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 [photovoltaic] 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 [U.S. Energy Information Administration] 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.”
[301] 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.”
[302] Report: “Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013.” U.S. Energy Information Administration, January 28, 2013. <www.justfacts.com>
Page 1: “Costs are estimated using tax depreciation schedules consistent with current law, which vary by technology.”
[303] Email from Just Facts to the U.S. Energy Information Administration on February 19, 2016:
“Are LCOE [levelized cost of electricity] 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.
[304] Email from Just Facts to the U.S. Energy Information Administration on August 13, 2013:
“Are the LACE [levelized avoided cost of electricity] values in the discussion paper calculated under the assumption that the financial life of all technologies is 30 years (like LCOE [levelized cost of electricity])?”
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.”
[305] Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2022.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Page 6: “We calculate all levelized costs and values based on a 30-year cost recovery period, using a nominal after-tax weighted average cost of capital (WACC) of 6.2%.8 In reality, a plant’s cost recovery period and cost of capital can vary by technology and project type.”
[306] Email from the U.S. Energy Information Administration to Just Facts on August 26, 2013:
EIA [U.S. Energy Information Administration] 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 [photovoltaic] 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).
[307] “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 [photovoltaic] 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.
[308] 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.
[309] Report: “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2022.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Pages 11–12:
When the LACE [levelized avoided cost of electricity] of a particular technology exceeds its LCOE [levelized cost of electricity] or LCOS [levelized cost of storage], that technology would generally be economically attractive to build. The build decisions in actuality (and as we model in AEO2022), however, are more complex than a simple LACE-to-LCOE or LACE-to-LCOS comparison because they include factors such as policy and non-economic drivers. Nevertheless, the value-cost ratio (the ratio of LACE-to-LCOE or LACE-to-LCOS) provides a reasonable point of comparison of first-order economic competitiveness among a wider variety of technologies than is possible using LCOE, LCOS, or LACE tables individually. In Tables 4a and 4b, a value index of less than one indicates that the cost of the marginal new unit of capacity exceeds its value to the system, and a value-cost ratio greater than one indicates that the marginal new unit brings in value higher than its cost by displacing more expensive generation and capacity options. The average value-cost ratio is an average of 25 regional LACE-to-LCOE or LACE-to-LCOS ratios. The range of the LACE-to-LCOE or LACE-to-LCOS ratios represents the lower and upper bounds of the regional LACE-to-LCOE and LACE-to-LCOS ratios, and it is not based on the ratio between the minimum and maximum values shown in Tables 2 and 3.
[310] Calculated with data from:
a) Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2022.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Page 9: “Table 1b. Estimated Unweighted Levelized Cost of Electricity (LCOE) and Levelized Cost of Storage for New Resources Entering Service in 2027 (2021 Dollars Per Megawatthour)”
Page 13: “Table 4b. Value-Cost Ratio (Unweighted) for New Resources Entering Service in 2027”
b) Report: “Levelized Costs of New Generation Resources in the Annual Energy Outlook 2021.” U.S. Energy Information Administration, February 2021. <www.eia.gov>
Page 6: “Starting in AEO [Annual Energy Outlook] 2020, EIA represents an ultra-supercritical9 (USC) coal generation technology without carbon capture and sequestration (CCS). In December 2018, the U.S. Environmental Protection Agency (EPA) amended earlier 2015 findings that partial CCS was the best system of emissions reductions (BSER) for greenhouse gas reductions and proposed to replace it with the most efficient demonstrated steam cycle, which EIA assumes is represented by ultra-supercritical coal technology. Regulatory or court actions related to power plant emissions taken after September 2020 are not accounted for in AEO2021. …9 USC coal plants are compatible with CCS technologies because they use boilers that heat coal to higher temperatures, which increases the pressure of steam to improve efficiency and results in less coal use and fewer carbon emissions than other boiler technologies.”
NOTE: An Excel file containing the data and calculations is available upon request.
[311] 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 sizable 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.
[312] Calculated with data from the report: “Electric Power Monthly with Data for January 2022.” U.S. Energy Information Administration, Office of Energy Statistics, March 24, 2022. <www.eia.gov>
Page 17 (of PDF): “Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
Page 18 (of PDF): “Table 1.1.A. Net Generation from Renewable Sources: Total (All Sectors), 2012–January 2022 (Thousand Megawatthours)”
NOTES:
[313] 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.”
[314] “Energy Primer: A Handbook of Energy Market Basics.” Federal Energy Regulatory Commission, November 2015. <www.ferc.gov>
Page 49: “Oil-fired plants generally produce only a small amount of the total electricity generated in the U.S. power markets. These facilities are expensive to run and also emit more pollutants than gas plants.”
[315] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 169: “Table 9.9. Cost of Fossil-Fuel Receipts at Electric Generating Plants (Dollars per Million Btua, Including Taxes)”
NOTE: An Excel file containing the data and calculations is available upon request.
[316] Textbook: The Chemistry and Technology of Petroleum (4th 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 [American Society for Testing and Materials], 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.”
[317] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 352:
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.
Page 358: “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.”
Page 360: “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.”
Page 362:
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.
Page 364: “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.”
Page 369: “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.”
[318] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 358: “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.”
Page 360: “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.”
Page 364: “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.”
[319] Textbook: The Chemistry and Technology of Petroleum (4th 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.”
[320] 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….
[321] 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 precursors 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.
[322] 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.
[323] Article: “Feuding Over the Origins of Fossil Fuels.” By Lisa M. Pinsker. American Geological Institute Geotimes, 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.
[324] Textbook: The Chemistry and Technology of Petroleum (4th 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….
[325] 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.”
[326] 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…. 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.
[327] 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 …
10 Terminals 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
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.”
[328] Textbook: The Chemistry and Technology of Petroleum (4th 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.”
[329] 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 [Pipeline and Hazardous Materials Safety Administration] and pipeline operators are engaged in research to identify and develop more effective means of ensuring the safety of energy pipelines.
[330] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 352:
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.
[331] Textbook: The Chemistry and Technology of Petroleum (4th 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.”
[332] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 7: “Table 1.3 Primary Energy Consumption by Source (Quadrillion Btu) … Fossil Fuelsa … 2021 Total … Petroleumd [=] 35.071 … 2021 Total … Totalg [=] R97.331”
CALCULATION: 35.071 / 97.331 = 36%
[333] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 41: “Table 2.2. Residential Sector Energy Consumption”
Page 43: “Table 2.3. Commercial Sector Energy Consumption”
Page 45: “Table 2.4. Industrial Sector Energy Consumption”
Page 47: “Table 2.5. Transportation Sector Energy Consumption”
Page 49: “Table 2.6. Electric Power Sector Energy Consumption”
NOTE: An Excel file containing the data and calculations is available upon request.
[334] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1 Petroleum Overview (Thousand Barrels per Day)”
NOTE: An Excel file containing the data and calculations is available upon request.
[335] Webpage: “Oil: Crude and Petroleum Products Explained, Oil Imports and Exports.” U.S. Energy Information Administration. Last updated May 1, 2018. <bit.ly>
U.S. petroleum imports peaked in 2005 and generally declined up until 2015. This trend was the result of many factors, including a decline in consumption, increased use of domestic biofuels (ethanol in gasoline and biodiesel in diesel fuel), and increased domestic production of crude oil and hydrocarbon gas liquids. The economic downturn following the financial crisis of 2008, improvements in vehicle fuel economy, and changes in consumer behavior contributed to the decline in U.S. petroleum consumption. Imports and consumption both increased in 2015 through 2017.
NOTE: This webpage includes renewable fuels in the totals for petroleum products. In keeping with the precise definition of petroleum and EIA’s [U.S. Energy Information Administration’s] data cited above, Just Facts does not include renewable fuels in totals for petroleum products.
[336] Webpage: “Oil: Crude and Petroleum Products Explained, Oil Imports and Exports—Basics.” U.S. Energy Information Administration. Last updated June 9, 2015. <bit.ly>
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 [U.S. Energy Information Administration’s] data cited above, Just Facts does not include renewable fuels in the totals for petroleum products.
[337] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[338] Article: “Covid-19 Mitigation Efforts Result in the Lowest U.S. Petroleum Consumption in Decades.” By Jesse Barnett. U.S. Energy Information Administration, April 23, 2020. <www.eia.gov>
U.S. consumption of petroleum products has fallen to its lowest level in decades because of measures that limit travel and because of the general economic slowdown induced by mitigation efforts for the coronavirus disease 2019 (Covid-19). …
Motor gasoline consumption has declined the most in absolute terms. Before many businesses were shut down and stay-at-home orders were issued, motor gasoline product supplied averaged 8.9 million b/d, based on 2020 data through March 13. Since then, motor gasoline product supplied has fallen 40% to 5.3 million b/d as of the week ending April 17. This decrease in motor gasoline product supplied accounts for 54% of the total change in product supplied. U.S. consumption of jet fuel experienced the largest drop in relative terms, declining 62% from a pre-shutdown average of 1.6 million b/d to just 612,000 b/d on April 17.
[339] Webpage: “Oil and Petroleum Products Explained: Oil Imports and Exports.” U.S. Energy Information Administration. Last updated April 13, 2021. <bit.ly>
In 2020, the United States exported about 8.51 MMb/d and imported about 7.86 MMb/d of petroleum,1 making the United States a net annual petroleum exporter for the first time since at least 1949. Also in 2020, the United States produced2 about 18.40 million barrels per day (MMb/d) of petroleum, and consumed3 about 18.12 MMb/d. Even though in 2020, total U.S. annual petroleum production was greater than total petroleum consumption and exports were greater than imports, the United States still imported some crude oil and petroleum products from other countries to help to supply domestic demand for petroleum and to supply international markets. …
After generally increasing every year from 1954 through 2005, U.S. total gross and net petroleum imports peaked in 2005. Increases in domestic petroleum production and in petroleum exports helped to reduce total annual petroleum net imports every year except one since 2005. In 2020, annual petroleum net imports were actually negative (at –0.65 MMb/d), the first time this occurred since at least 1949.
NOTE: This webpage includes renewable fuels in the totals for petroleum products. In keeping with the precise definition of petroleum and EIA’s [U.S. Energy Information Administration’s] data cited above, Just Facts does not include renewable fuels in totals for petroleum products.
[340]Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61:
Table 3.1 Petroleum Overview (Thousand Barrels per Day)
|
Year |
Consumption |
Imports |
|
(Million Barrels Per Year) |
||
|
2005 |
7,593 |
4,580 |
|
2006 |
7,551 |
4,523 |
|
2007 |
7,548 |
4,393 |
|
2008 |
7,117 |
4,056 |
|
2009 |
6,579 |
3,528 |
|
2010 |
6,669 |
3,446 |
|
2011 |
6,526 |
3,084 |
|
2012 |
6,394 |
2,698 |
|
2013 |
6,557 |
2,277 |
|
2014 |
6,587 |
1,849 |
|
2015 |
6,729 |
1,719 |
|
2016 |
6,765 |
1,750 |
|
2017 |
6,845 |
1,375 |
|
2018 |
7,036 |
855 |
|
2019 |
7,087 |
244 |
|
2020 |
6,270 |
–232 |
|
2021 |
6,809 |
–60 |
NOTES:
[341] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day)”
NOTE: An Excel file containing the data and calculations is available upon request.
[342] Calculated with the dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, July 29, 2022. <www.eia.gov>
“Net Imports of Total Crude Oil and Products into the U.S. by Country 1973–2021” <www.eia.gov>
NOTES:
[343] Calculated with the dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, July 29, 2022. <www.eia.gov>
“Net Imports of Total Crude Oil and Products into the U.S. by Country 1973–2021” <www.eia.gov>
NOTES:
[344] Calculated with the dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, July 29, 2022. <www.eia.gov>
“Net Imports of Total Crude Oil and Products into the U.S. by Country 1973–2021” <www.eia.gov>
NOTES:
[345] Webpage: “Our Mission.” Organization of the Petroleum Exporting Countries. Accessed August 18, 2022. <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.
[346] Webpage: “Member Countries.” Organization of the Petroleum Exporting Countries. Accessed August 18, 2022 at <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), Angola (2007), Equatorial Guinea (2017) and Congo (2018).
Ecuador suspended its membership in December 1992, rejoined OPEC in October 2007, but decided to withdraw its membership of OPEC effective 1 January 2020. Indonesia suspended its membership in January 2009, reactivated it again in January 2016, but decided to suspend its membership once more at the 171st Meeting of the OPEC Conference on 30 November 2016. Gabon terminated its membership in January 1995. However, it rejoined the Organization in July 2016. Qatar terminated its membership on 1 January 2019.
This means that, currently, the Organization has a total of 13 Member Countries.
[347] “OPEC Statute.” Organization of the Petroleum Exporting Countries, 2021. <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.
[348] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[349] 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 [Organization of the Petroleum Exporting Countries] 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.
[350] 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 [Organization of the Petroleum Exporting Countries] has used both the strategies to ensure its control over the oil market.
[351] 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 [Organization of the Petroleum Exporting Countries] 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.
[352] 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 [Organization of the Petroleum Exporting Countries] 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 [United Arab Emirates]—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.
[353] Article: “There’s One Place Where OPEC [Organization of the Petroleum Exporting Countries] 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.
[354] 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 [Organization of the Petroleum Exporting Countries] 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.
[355] 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 [Organization of the Petroleum Exporting Countries] 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 Minister 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.
[356] Article: “5 Charts That Explain the Saudi Arabia–Russia Oil Price War So Far.” CNBC, April 1, 2020. <www.cnbc.com>
Two of the world’s largest oil producers—Saudi Arabia and Russia—are set to increase production dramatically this month, after an agreement between OPEC [Organization of the Petroleum Exporting Countries] and its allies to lower output expired at the end of March.
OPEC+ countries have teamed up to reduce their supply to the market since 2017, but failed to reach a deal last month.
Riyadh and Moscow then separately announced that they would flood the market with oil in April. That, against the backdrop of demand destruction due to the global coronavirus pandemic, has crushed oil prices. Crude oil benchmarks plunged to 18-year lows on Tuesday and have fallen more than 60% since the beginning of the year.
[357] Article: “From the Barrel to the Pump: The Impact of the Covid-19 Pandemic on Prices for Petroleum Products.” By Kevin M. Camp and others. U.S. Bureau of Labor Statistics Monthly Labor Review, October 2020. <doi.org>
As the Covid-19 pandemic continued to spread across the world, Saudi Arabia, the world’s second-largest oil producer behind the United States, urged fellow Organization of the Petroleum Exporting Countries (OPEC) members and Russia to cut production.5 Having formed a 2016 alliance with OPEC to control the price of oil through production cuts, Russia, the world’s third-largest oil producer, now resisted the call for further reductions in response to the pandemic. Russia sought to gain market share in anticipation that the U.S. shale industry’s profitability and output would fall in the face of lower prices.6 … By the beginning of April, OPEC had raised output by 1.7 million barrels per day, up to a level of 30.4 million barrels per day, the largest production jump since September 1990. According to Bloomberg, Saudi Arabia alone reached a record production of 12.3 million barrels per day on April 1, an output exceeding the pre-pandemic consumption levels of Japan, Germany, France, the United Kingdom, Italy, and Spain combined.8 The production boom coincided with an International Energy Agency (IEA) estimate that global demand for oil was down by almost 30 million barrels per day because of the shutdowns in response to the Covid-19 pandemic.9 With demand down, the addition of petroleum to an already saturated market led to a near-record level of 535.2 million barrels of crude petroleum stockpiles in the United States on May 1.10
[358] 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.” <www.eia.gov>
b) Dataset: “U.S. Net Imports by Country.” U.S. Energy Information Administration, Office of Energy Statistics, July 29, 2022. <www.eia.gov>
“Net Imports of Total Crude Oil and Products into the U.S. by Country 1973–2021” <www.eia.gov>
NOTES:
[359] Webpage: “Oil Prices and Outlook.” U.S. Energy Information Administration. Last updated July 2, 2019. <www.eia.gov>
Crude oil prices are determined by global supply and demand. Economic growth is one of the biggest factors affecting petroleum product—and therefore crude oil—demand. Growing economies increase demand for energy in general and especially for transporting goods and materials from producers to consumers. …
The Organization of the Petroleum Exporting Countries (OPEC) can have a significant influence on oil prices by setting production targets for its members. OPEC includes countries with some of the world's largest oil reserves. As of the end of 2018, OPEC members controlled about 72% of total world proved oil reserves, and in 2018, they accounted for 41% of total world crude oil production.
[360] Webpage: “Spot Prices.” U.S. Energy Information Administration. Accessed April 5, 2018 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.
[361] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fas.org>
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 [European Union] 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 … Tightening sanctions have prompted Iranian officials to threaten closing the Strait of Hormuz, a critical thoroughfare of the global oil trade. …
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 [U.S. Energy Information Administration], 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.
[362] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[363] Article: “5 Charts That Explain the Saudi Arabia–Russia Oil Price War So Far.” CNBC, April 1, 2020. <www.cnbc.com>
Two of the world’s largest oil producers—Saudi Arabia and Russia—are set to increase production dramatically this month, after an agreement between OPEC [Organization of the Petroleum Exporting Countries] and its allies to lower output expired at the end of March.
OPEC+ countries have teamed up to reduce their supply to the market since 2017, but failed to reach a deal last month.
Riyadh and Moscow then separately announced that they would flood the market with oil in April. That, against the backdrop of demand destruction due to the global coronavirus pandemic, has crushed oil prices. Crude oil benchmarks plunged to 18-year lows on Tuesday and have fallen more than 60% since the beginning of the year.
[364] Article: “From the Barrel to the Pump: The Impact of the Covid-19 Pandemic on Prices for Petroleum Products.” By Kevin M. Camp and others. U.S. Bureau of Labor Statistics Monthly Labor Review, October 2020. <doi.org>
By the beginning of April [2020], OPEC [Organization of the Petroleum Exporting Countries] had raised output by 1.7 million barrels per day, up to a level of 30.4 million barrels per day, the largest production jump since September 1990. … The production boom coincided with an International Energy Agency (IEA) estimate that global demand for oil was down by almost 30 million barrels per day because of the shutdowns in response to the Covid-19 pandemic.9 With demand down, the addition of petroleum to an already saturated market led to a near-record level of 535.2 million barrels of crude petroleum stockpiles in the United States on May 1.10
Prices dropped precipitously in March and April 2020. The combination of falling demand, rising supply, and diminishing storage space caused such a pronounced crude petroleum price plunge that, on April 20, crude petroleum traded at a negative price in the intraday futures market. …
The recurrence of Covid-19 cases in the United States and other countries, as well as travel restrictions, led to a slower-than-expected recovery. Both the IEA and OPEC made downward revisions to their earlier demand forecasts for 2020. For both 2020 and 2021, world petroleum demand is projected to decline from 2019 levels.
[365] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 159: “Table 9.1: Crude Oil Price Summary”
Page 161: “Table 9.3: Landed Costs of Crude Oil Imports From Selected Countries … On this table, ‘Total OPEC [Organization of the Petroleum Exporting Countries]’ for all years includes Algeria, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela; Angola is included in ‘Total OPEC’ 2007 forward; Gabon is included in ‘Total OPEC’ 1974–1995 and July 2016 forward; Ecuador is included in ‘Total OPEC’ 1973–1992 and 2008 forward; Indonesia is included in ‘Total OPEC’ 1973–2008 and 2016.”
b) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed February 5, 2022 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[366] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 159: “Table 9.1: Crude Oil Price Summary”
Page 161: “Table 9.3: Landed Costs of Crude Oil Imports From Selected Countries … On this table, ‘Total OPEC [Organization of the Petroleum Exporting Countries]’ for all years includes Algeria, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, and Venezuela; Angola is included in ‘Total OPEC’ 2007 forward; Gabon is included in ‘Total OPEC’ 1974–1995 and July 2016 forward; Ecuador is included in ‘Total OPEC’ 1973–1992 and 2008 forward; Indonesia is included in ‘Total OPEC’ 1973–2008 and 2016.”
b) Dataset: “CPI—All Urban Consumers (Current Series).” U.S. Department of Labor, Bureau of Labor Statistics. Accessed February 5, 2022 at <www.bls.gov>
“Series Id: CUUR0000SA0; Series Title: All Items in U.S. City Average, All Urban Consumers, Not Seasonally Adjusted; Area: U.S. City Average; Item: All Items; Base Period: 1982–84=100”
NOTE: An Excel file containing the data and calculations is available upon request.
[367] Webpage: “Factors Affecting Gasoline Prices.” U.S. Energy Information Administration. Last updated March 15, 2022. <www.eia.gov>
“What do we pay for per gallon of retail regular grade gasoline … 2021 Average Retail Price: $3.01/gallon … refining costs and profits [=] 14.4% … distribution and marketing [=] 15.6% … federal and state taxes [=] 16.4% … crude oil [=] 53.6%”
[368] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 352:
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.
[369] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 5, 2012. <www.gao.gov>
Page 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.”
[370] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[371] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 5, 2012. <www.gao.gov>
Page 2: “[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.
[372] 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 [U.S. Energy Information Administration] 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.
[373] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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-permeability138 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.
[374] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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.
12 Conventional 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.
13 For 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.
[375] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.
[376] 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.
[377] 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 <www.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.
[378] Webpage: “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.”
[379] 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.”
[380] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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.”
[381] 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 <www.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.
[382] 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 and others. <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.”
[383] 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 [horizontal displacement] 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.”
[384] 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.”
[385] 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 April 5, 2018 at <www.netl.doe.gov>
[386] 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.
[387] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[388] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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
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.
20 Stresses in the formation generally define a maximum and minimum stress direction that influence the direction a fracture will grow.
21 Underground 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.
[389] 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.”
[390] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 5, 2012. <www.gao.gov>
Page 7:
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.
[391] Webpage: “Factors Affecting Gasoline Prices.” U.S. Energy Information Administration. Last updated March 6, 2018. <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.
[392] Report: “Rising Gasoline Prices 2012.” By Neelesh Nerurkar and Robert Pirog. Congressional Research Service, March 1, 2012. <fas.org>
Page 4: “Meanwhile, global demand has reached new highs. According to EIA [Energy Information Administration], 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.”
[393] 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 [British Petroleum] 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.”
[394] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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
15 Hydraulic 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.”
[395] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.
[396] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 [Annual Energy Outlook] 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.”
[397] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day)”
NOTE: An Excel file containing the data and calculations is available upon request.
[398] Article: “U.S. Crude Oil Production Grew 11% in 2019, Surpassing 12 Million Barrels Per Day.” U.S. Energy Information Administration, March 2, 2020. <www.eia.gov>
Annual U.S. crude oil production reached another record level at 12.23 million barrels per day (b/d) in 2019, 1.24 million b/d, or 11%, more than 2018 levels. The 2019 growth rate was down from a 17% growth rate in 2018. In November 2019, monthly U.S. crude oil production averaged 12.86 million b/d, the most monthly crude oil production in U.S. history, according to the U.S. Energy Information Administration’s (EIA) Petroleum Supply Monthly. U.S. crude oil production has increased significantly during the past 10 years, driven mainly by production from tight rock formations developed using horizontal drilling and hydraulic fracturing to extract hydrocarbons.
[399] 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 [U.S. Energy Information Administration] estimates that oil production from hydraulically fractured wells now makes up about half of total U.S. crude oil production.
[400] 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] 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.
[401] 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.
[402] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[403] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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.”
[404] Calculated with data from:
a) Webpage: “How Much Shale (Tight) Oil Is Produced in the United States?” U.S. Energy Information Administration. Last updated March 7, 2022. <www.eia.gov>
“The U.S. Energy Information Administration (EIA) estimates that in 2021, about 2.64 billion barrels (or about 7.22 million barrels per day) of crude oil were produced directly from tight oil resources in the United States. This was equal to about 65% of total U.S. crude oil production in 2021.”
b) Article: “Horizontally Drilled Wells Dominate U.S. Tight Formation Production.” By Jack Perrin. U.S. Energy Information Administration, June 6, 2019. <www.eia.gov>
“In 2004, horizontal wells accounted for about 15% of U.S. crude oil production in tight oil formations. By the end of 2018, that percentage had increased to 96%. … Because tight formations have very low permeability, which prevents oil and gas from moving toward the well bore, using hydraulic fracturing to increase permeability, along with horizontal drilling, is necessary for oil and gas to be produced from these formations economically.”
CALCULATION: 65% of crude oil production from tight oil formations × 96% of tight oil production from horizontal wells = 62.4% of crude oil production from horizontal wells
[405] Article: “Tight Oil Development Will Continue to Drive Future U.S. Crude Oil Production.” By Dana Van Wagener and Faouzi Aloulou. U.S. Energy Information Administration, March 28, 2019. <www.eia.gov>
“Tight oil production reached 6.5 million b/d [barrels per day] in the United States in 2018, accounting for 61% of total U.S. production. EIA projects further U.S. tight oil production growth as the industry continues to improve drilling efficiencies and reduce costs, which makes developing tight oil resources less sensitive to oil prices than in the past.”
[406] 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.
[407] Article: “On the Rise.” By Thomas Helbling. International Monetary Fund Finance & Development, 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.”
[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>):
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.
[409] 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.
[410] 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.
Canada is the only other country to produce both shale gas and tight oil. China produces some small volumes of shale gas, while Argentina produces some small volumes of tight oil. While hydraulic fracturing techniques have been used to produce natural gas and tight oil in Australia and Russia, the volumes produced did not come from low-permeability shale formations.
[411] Email from the U.S. Energy Information Administration to Just Facts on August 13, 2019:
“Tight oil production from shale formations is still limited to the U.S., Canada and Argentina.”
[412] Email from Just Facts to the U.S. Energy Information Administration on July 30, 2020:
“Is commercial production of tight oil from shale formations is still limited to the U.S., Canada, and Argentina?”
Email from the U.S. Energy Information Administration to Just Facts on July 31, 2020:
“I believe you are correct and commercial production of tight oil and shale is still restricted to those countries. However this is not an area that we have been focusing our research efforts in recently.”
[413] Email from the U.S. Energy Information Administration to Just Facts on July 6,
2021:
“Commercial production of tight oil from shale formations is still limited to the U.S., Canada, and Argentina.”
[414] Email from Just Facts to the U.S. Energy Information Administration on August 29, 2022:
“Is commercial production of tight oil from shale formations is still limited to the U.S., Canada, and Argentina?
”Email from the U.S. Energy Information Administration to Just Facts on August 29, 2022:
“That’s correct, and most probably not very accurate. China has produced tight oil, using some fracking techniques for years. Their definition of tight oil is not what an American geologist or a petroleum engineer would consider tight.”
[415] 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.
[416] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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 characteristics72, 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 [estimated ultimate recoveries] 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’).”
[417] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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 [U.S. Energy Information Administration] 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 [U.S. Geological Survey] has not yet evaluated the Monterey Shale play.
[418] Report: “Assumptions to the Annual Energy Outlook 2022: Oil and Gas Supply Module.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Page 2:
A common measure of the long-term viability of U.S. domestic crude oil and natural gas as energy sources is the remaining TRR [technically recoverable resources], which consists of proved reserves4 and unproved resources.5 Estimates of TRR are highly uncertain, particularly in emerging plays where relatively few wells have been drilled. Early estimates tend to vary and shift significantly over time because new geological information is gained through additional drilling, long-term productivity is clarified for existing wells, and the productivity of new wells increases with technology improvements and better management practices. The TRR estimates that we use [U.S. Energy Information Administration] for each Annual Energy Outlook (AEO) are based on the latest available well production data and information from other federal and state governmental agencies, industries, and academia.
Page 7:
The underlying resource assumptions for the AEO Reference case is uncertain, particularly as exploration and development of tight oil continues to move into areas with little or no production history. Many wells drilled in tight or shale formations using the latest technologies have less than two years of production history, so we cannot fully ascertain the impact of recent technological advancement on the estimate of future recovery. Uncertainty also extends to the extent of formations and the number of layers in an area that could be drilled within formations. Alternative resource cases are addressed at the end of this document.
[419] 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.”
[420] 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.
[421] 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 [U.S. Geological Survey] is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.”
[422] 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.
[423] 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.”
[424] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 369: “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.”
[425] Webpage: “Do We Have Enough Oil Worldwide to Meet Our Future Needs?” U.S. Energy Information Administration. Last updated November 2, 2021. <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.
[426] 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.
[427] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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 [U.S. Energy Information Administration] 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.
[428] 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 [U.S. Geological Survey] 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.
[429] Paper: “Percentage Depletion For Oil – A Policy Issue.” By Harrop A. Freeman. Indiana Law Journal, July 1, 1955. Pages 399–429. <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,103 oil from shale and tar sands,104 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
[430] 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.
[431] Webpage: “Paul R. Ehrlich.” Stanford University. Accessed March 15, 2019 at <ccb.stanford.edu>
President, Center for Conservation Biology, Bing Professor of Population Studies Emeritus …
Professor Ehrlich has received several honorary degrees, the John Muir Award of the Sierra Club, the Gold Medal Award of the World Wildlife Fund International, a MacArthur Prize Fellowship, the Crafoord Prize of the Royal Swedish Academy of Sciences (given in lieu of a Nobel Prize in areas where the Nobel is not given), in 1993 the Volvo Environmental Prize, in 1994 the United Nations’ Sasakawa Environment Prize, in 1995 the Heinz Award for the Environment, in 1998 the Tyler Prize for Environmental Achievement and the Dr. A. H. Heineken Prize for Environmental Sciences, in 1999 the Blue Planet Prize, in 2001 the Eminent Ecologist Award of the Ecological Society of America and the Distinguished Scientist Award of the American Institute of Biological Sciences, and in 2009 the Margalef Prize in Ecology and Environmental Sciences.
[432] Webpage: “Paul R. Ehrlich.” Stanford University, November 2018. <ccb.stanford.edu>
“Professor of Biological Sciences, Stanford University, 1966–2015 (emeritus 2016) … Bing Professor of Population Studies, Stanford University, 1977–2015 (emeritus 2016) … President—Center for Conservation Biology, 1984–present”
[433] Article: “The Book That Incited a Worldwide Fear of Overpopulation.” By Charles C. Mann. Smithsonian, January 2018. <www.smithsonianmag.com>
As 1968 began, Paul Ehrlich was an entomologist at Stanford University, known to his peers for his groundbreaking studies of the co-evolution of flowering plants and butterflies but almost unknown to the average person. That was about to change. In May, Ehrlich released a quickly written, cheaply bound paperback, The Population Bomb. Initially it was ignored. But over time Ehrlich’s tract would sell millions of copies and turn its author into a celebrity. It would become one of the most influential books of the 20th century—and one of the most heatedly attacked.
[434] Book: The End of Affluence: A Blueprint for Your Future. By Paul R. Ehrlich and Anne H. Ehrlich. Ballantine Books, 1974.
Page 49:
What Will We Do When the Pumps Run Dry?
Assuming no serious attempt is made to reduce worldwide consumption, how long will mankind’s liquid petroleum supplies last?
The US is now using a third of all the world’s petroleum extracted each year. Our energy wastage is enormous…. Furthermore, some projections indicate that by shortly after the turn of the century, Americans alone will “demand” each year more than today’s annual world production. No reasonable supply–demand scenario can be created that will meet such demand. The figures presented in the previous section clearly show that by early in the twenty-first century, the era of pumping “black gold” out of the ground to fuel industrial societies will be coming to an end.
We can be reasonably sure, then, that within the next quarter of a century mankind will be looking elsewhere than in oil wells for its main source of energy.
[435] Calculated with the dataset: “Crude Oil Including Lease Condensate Production (Mb/D).” U.S. Energy Information Administration. Accessed August 19, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[436] Report: “Assumptions to the Annual Energy Outlook 2022: Oil and Gas Supply Module.” U.S. Energy Information Administration, March 2022. <www.eia.gov>
Page 2:
Key Assumptions
Domestic Oil and Natural Gas Technically Recoverable Resources
The outlook for domestic crude oil production is highly dependent on 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, we re-estimate initial production (IP) rates and production decline curves, which determine estimated ultimate recovery (EUR) per well and total technically recoverable resources (TRR).3
A common measure of the long-term viability of U.S. domestic crude oil and natural gas as energy sources is the remaining TRR, which consists of proved reserves4 and unproved resources.5 Estimates of TRR are highly uncertain, particularly in emerging plays where relatively few wells have been drilled. Early estimates tend to vary and shift significantly over time because new geological information is gained through additional drilling, long-term productivity is clarified for existing wells, and the productivity of new wells increases with technology improvements and better management practices. The TRR estimates that we use for each Annual Energy Outlook (AEO) are based on the latest available well production data and information from other federal and state governmental agencies, industries, and academia.
Table 1. Technically Recoverable U.S. Crude Oil Resources as of January 1, 2020 (billion barrels) …
Total Technically Recoverable Resources … Total United States [=] 373.1 …
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.
NOTE: Although this EIA [U.S. Energy Information Administration] 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: “March 2018 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, March 27, 2018. <www.eia.gov>. Pages 221–222.]
[437] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Productiona … Crude Oilb,c … Total … 2020 Average [=] 11,283 … b Includes lease condensate.”
CALCULATIONS:
[438] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Productiona … Crude Oilb,c … Total … 2020 Average [=] 11,283 … Trade … Net Importsh … 2020 Average [=] –635 … b Includes lease condensate.”
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 time determined in the calculation below.
CALCULATIONS:
[439] 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.
[440] Calculated with data from the report: “International Energy Outlook 2017.” U.S. Energy Information Administration, September 14, 2017. <www.eia.gov>
“Table G2. World crude oil production by region and country.” <www.eia.gov>
“Total World … 2013 [=] 75.9 [million barrels per day]”
CALCULATION: 3,357,000,000,000 barrels / (75,900,000 barrels per day × 365 days/year) = 121 years
[441] Article: “DOE [U.S. Department of Energy]-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.”
[442] 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 and others. <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.
[443] 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).”
[444] 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 April 7, 2018 at <www.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.”
[445] 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.
[446] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Production … Crude Oil … Total … 2013 Average [=] 7,498 … Trade … Net Imports … 2013 Average [=] 6,237”
NOTES:
CALCULATIONS:
[447] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 61: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Production … Crude Oil … Total … 2013 Average [=] 7,498
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 time determined in the calculations below.
CALCULATIONS:
[448] Calculated with data from the report: “International Energy Outlook 2017.” U.S. Energy Information Administration, September 14, 2017. <www.eia.gov>
“Table G2. World crude oil production by region and country, Reference Case.” <www.eia.gov>
“Total World … 2013 [=] 76.0 [million barrels per day]”
CALCULATIONS:
[449] 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 April 7, 2018 at <www.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.”
[450] 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>) Page 3: “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: “January 2024 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, January 29, 2024. <www.eia.gov>
Page 63: “Table 3.1: Petroleum Overview (Thousand Barrels per Day) … Field Productiona … Crude Oilb,c … Total … 2022 Average [=] 11,911 ... Trade … Net Importsh … 2022 Average [=] –1,191”
NOTE: An Excel file containing the data and calculations is available upon request.
[451] 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>) Page 3: “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: “Crude Oil Including Lease Condensate Production (Mb/D).” U.S. Energy Information Administration. Accessed February 1, 2024 at <www.eia.gov>
“World … 2022 [=] 80,833”
NOTE: An Excel file containing the data and calculations is available upon request.
[452] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
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 STP 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.
[453] 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).”
[454] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Pages 360–362:
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.
[455] 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.”
Page 360: “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.”
Page 364: “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.”
Page 362:
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.
[456] Report: “Annual Energy Review 2011.” U.S. Energy Information Administration, Office of Energy Statistics, September 2012. <www.eia.gov>
Page 358: “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.”
Page 361: “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.”
[457] 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.”
[458] 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.
[459] Article: “Feuding Over the Origins of Fossil Fuels.” By Lisa M. Pinsker. American Geological Institute Geotimes, 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.
[460] 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.”
[461] Calculated from the dataset: “U.S. Natural Gas Flow, 2021 (Trillion Cubic Feet).” U.S. Energy Information Administration, Office of Energy Statistics, April 2022. <www.eia.gov>
“trillion cubic feet … from crude oil wells 4.71 … gross withdrawals 41.49”
CALCULATION: 4.71 trillion cubic feet of gas from crude oil wells / 41.49 trillion cubic feet of gas from all wells = 11.4%
[462] 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.
[463] 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.
[464] Textbook: The Chemistry and Technology of Petroleum (4th 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.
[465] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
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.
[466] Textbook: The Chemistry and Technology of Petroleum (4th 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.
[467] 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>. Page 353: “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
[468] 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.
[469] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
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 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 labor and maintenance, are low.
[470] 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.
[471] Textbook: The Chemistry and Technology of Petroleum (4th 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.
[472] Webpage: “Glossary.” U.S. Energy Information Administration. Accessed July 22, 2019 at <www.eia.gov>
“Vented/Flared: Gas that is disposed of by releasing (venting) or burning (flaring).”
[473] 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 181: “Table 6.2: Natural Gas Production, Selected Years, 1949–2011 (Billion Cubic Feet)”
b) Webpage: “Total Energy: Energy Flow Archives.” U.S. Energy Information Administration, Office of Energy Statistics. Accessed August 24, 2022 at <www.eia.gov>
“Energy Flow Diagrams 1996–2020: Natural Gas.”
1996, 1997, 1998, 1999, 2000, 2001, 2002, 2003, 2004, 2005, 2006, 2007, 2008, 2009, 2010, 2011, 2012, 2013, 2014, 2015, 2016, 2017, 2018, 2019, 2020
c) Webpage “U.S. Natural Gas Flow, 2021.” U.S. Energy Information Administration, Office of Energy Statistics. Accessed August 24, 2022 at <www.eia.gov>
NOTE: An Excel file containing the data and calculations is available upon request.
[474] Calculated from the webpage: “Total Energy: Energy Flow Archives.” U.S. Energy Information Administration, Office of Energy Statistics. Accessed August 24, 2022 at <www.eia.gov>
“U.S. Natural Gas Flow, 2020 … Vented and Flared [=] 0.56 … Marketed Production [=] 36.18”
CALCULATION: 0.56 trillion cubic feet of vented and flared gas / 36.18 trillion cubic feet of marketed production gas = 1.5%
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.
[475] Calculated with data from:
a) Website: “Global Gas Flaring Data.” World Bank. Accessed August 25, 2022 at <www.worldbank.org>
“Individual Flare Sites – Gas Flaring Volumes (mln m3/yr) … Year [=] 2020 … Region [=] All … Location [=] All … Flare Size [=] All … Economy [=] All … Field Type [=] All … Flare Volume [=] 141,377.60”
b) Report: “Key World Energy Statistics 2021.” International Energy Agency, September 2021. <iea.blob.core.windows.net>
Page 15: “Producers, Net Exporters and Net Importers1 of Natural Gas …Producers … World … bcm [=] 4,014 … 2020 provisional data”
CALCULATION: 141.378 bcm flared gas / 4,014 bcm natural gas production = 3.5%
[476] Book: Fundamentals of Natural Gas. By Vivek Chandra. Pennwell, 2006. <vdoc.pub>
More than 97% of the world’s synthetic fertilizer is produced from synthetically produced ammonia. 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, and is thus the feedstock of choice. …
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.
[477] 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. <fire.pppl.gov>
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.”
[478] 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 [natural gas liquids] 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.”
[479] Report: “Annual Energy Outlook 2013 with Projections to 2040.” U.S. Energy Information Administration, April 2013. <www.osti.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.
[480] Webpage: “What Are Natural Gas Liquids and How Are They Used?” U.S. Energy Information Administration, April 20, 2012. <www.eia.gov>
NGL [natural gas liquids] 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.
[481] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 7: “Table 1.3 Primary Energy Consumption by Source (Quadrillion Btu) … 2021 Total … Natural Gasc [=] 31.343 … Totalg [=] 97.331”
CALCULATION: 31.343 / 97.331 = 32.2%
[482] Calculated with data from the report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 41: “Table 2.2. Residential Sector Energy Consumption”
Page 43: “Table 2.3. Commercial Sector Energy Consumption”
Page 45: “Table 2.4. Industrial Sector Energy Consumption”
Page 47: “Table 2.5. Transportation Sector Energy Consumption”
Page 49: “Table 2.6. Electric Power Sector Energy Consumption”
NOTE: An Excel file containing the data and calculations is available upon request.
[483] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 103: “(Billion Cubic Feet)”
b) Report: “Natural Gas Annual 1994 Volume 2.” U.S. Energy Information Administration, Office of Energy Statistics, November 1995. <www.eia.gov>
Pages 6–7: “Table 2. Supply and Disposition of Natural Gas in the United States, 1930–1994 (Million Cubic Feet)”
NOTE: An Excel file containing the data and calculations is available upon request.
[484] Calculated with data from:
a) Report: “July 2022 Monthly Energy Review.” U.S. Energy Information Administration, Office of Energy Statistics, July 26, 2022. <www.eia.gov>
Page 103: “Table 4.1: Natural Gas Overview (Billion Cubic Feet)”
b) Report: “Natural Gas Annual 1994 Volume 2.” U.S. Energy Information Administration, Office of Energy Statistics, November 1995. <www.eia.gov>
Pages 6–7: “Table 2. Supply and Disposition of Natural Gas in the United States, 1930–1994 (Million Cubic Feet)”
NOTE: An Excel file containing the data and calculations is available upon request.
[485] Report: “Information on Shale Resources, Development, and Environmental and Public Health Risks.” U.S. Government Accountability Office, September 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.
[486] Report: “International Energy Outlook 2013.” U.S. Energy Information Administration, July 25, 2013. <www.eia.gov>
Page 4:
