Energy & Technology
- In the United States, petroleum is the largest energy source, accounting for 37 percent of all energy consumed in 2010 with the transportation sector accounting for over two-thirds of U.S. petroleum consumption.
- Correspondingly, petroleum is one of the largest sources of U.S. greenhouse gas emissions, accounting for around 32.5 percent of total U.S. greenhouse gas emissions in 2010.
- Globally, petroleum supplies 32.8 percent of global energy use and was responsible for 36.7 percent of global carbon dioxide emissions in 2009.
- The crude oil market is a global market. The United States has 1.4 percent of the world’s proved oil reserves, produces 11.1 percent of the world’s oil supply, and constitutes 22 percent of the world’s oil demand.
U.S. demand peaked in 2005 at 20.8 million barrels per day (b/d) and declined to 18.8 million b/d in 2011. Consumption is expected to remain below the 2005 level until 2035.
Crude oil is an organic compound composed of hydrogen and carbon (i.e., a hydrocarbon). The hydrogen provides us with energy and the carbon is generally a waste product that is emitted into the air upon combustion. In order to be useful, crude oil must be refined through distillation and chemical processes. The refining process separates the hydrocarbon chains into different petroleum products. In addition to gasoline, some of the most common products are:
• Petroleum gas – like methane, butane and propane used for heating and cooking
• Kerosene – fuel for jet engines, tractors and some heaters
• Naphtha or Ligroin – an intermediate product used to make gasoline
• Gas oil or diesel distillate – diesel fuel and heating oil
• Lubricants – motor oil, and grease
• Residuals Products – coke, asphalt/tar, waxes
A typical 42 gallon barrel of crude oil (Figure 1) yields around 45 gallons of petroleum products; the 3-gallon refinery gain is due to the fact that the refined products have a lower density than crude oil.
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Figure 1. Products Made from a Barrel of Crude Oil
Source: U.S. Energy Information Administration, “Oil: Crude and Petroleum Products Explained.” 2012
Globally, transportation accounts for 61.7 percent of petroleum consumption. The remaining uses are non-energy related, including lubricants and asphalt production and use (16.5 percent); agriculture, commercial and public services, residential, and non-specified other (12.5 percent); and industry (9.3 percent). In the United States, transportation accounts for over two-thirds of U.S. petroleum consumption, with the remainder used by the industrial (23.6 percent), residential and commercial (5.3 percent), and electric power sector (0.9 percent).
Figure 2. U.S. Petroleum Consumption by Sector (2010)
Source: U.S. Department of Energy, “Total Energy: Monthly Energy Review. Tables 3.7a, b and c.” March 28, 2012.
As shown in Figure 3, light-duty vehicles – cars and pickup trucks – account for almost two-thirds of transportation petroleum consumption with the rest used by medium- and heavy-duty trucks (22.8 percent), airplanes (8 percent), and water transport, such as ships (4.8 percent).
Figure 3. U.S. Consumption of Transportation Energy, Petroleum (2009)
Source: U.S. Department of Energy, “Transportation Energy Data Book.” June 25, 2011.
Petroleum, or crude oil, is formed from organic matter deposited millions of years ago. As the organic material decomposed, it mixed with other material like sand and silt and eventually formed sedimentary layers. Over time, heat and pressure from overlying rock layers in certain places forced the this organic material to move until it was trapped beneath less porous rock where it accumulated in what is known as oil reservoirs.
Generally, conventional oil resources refer to those that are most accessible and easiest to produce. Unconventional resources are less accessible and more difficult to produce. Examples of unconventional resources include shale oil, oil sands, and deep underwater resources. As known conventional supplies diminish and the price of oil rises, we are increasingly shifting to unconventional resources, and what was once unconventional is today becoming conventional. Note that the term “proven reserves” implies that the estimated quantities are deemed recoverable with reasonable certainty under existing economic and operating conditions.
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The combustion of petroleum emits a variety of pollutants – such as carbon dioxide, carbon monoxide, sulfur dioxide, nitrogen oxides, volatile organic compounds, and particulate matter. These pollutants are directly and indirectly linked to climate change, acid rain, and public health issues. As one of three fossil fuels, oil has less carbon content than coal, but more than natural gas. According to the U.S. Environmental Protection Agency’s 2012 U.S. Greenhouse Gas Inventory Report, CO2 emissions from petroleum accounted for 32.1 percent of total U.S. greenhouse gas emissions in 2010, ahead of coal (28.3 percent) and natural gas (18.5 percent). The transportation sector accounted for 77.8 percent of these CO2 emissions and the industrial sector (including refining) accounted for 13.1 percent. Within the transportation sector, gasoline and diesel contributed 90.1 percent of the CO2 emissions, 65.5 percent and 24.6 percent respectively. Petroleum refineries are one of the largest energy consumers in the industrial sector, accounting for about 2.7 percent of total U.S. GHG emission in 2010.
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Historically, the world oil market has been dominated by national oil companies, particularly through the exercise of market power by the Organization of Petroleum Exporting Countries. OPEC has 12 member countries: six in the Middle East, four in Africa and two in South America. OPEC accounts for around 72 percent of the world’s proven oil reserves.
Table 1. Top 20 Countries’ Crude Oil Reserves (Billion Barrels)
United Arab Emirates*
Source: U.S. Energy Information Administration, International Energy Statistics
In recent years, global oil production and reserve estimates have become more geographically diversified with unconventional oil such as Canadian oil sands playing an increasingly important role. A shift is also taking place in global demand patterns, with consumption in Asia now exceeding consumption in North America. Over the last 30 years, global petroleum consumption has increased by 26 percent, and reserves have increased by 109 percent. Asian demand has surged by nearly 15 million barrels per day (Figure 4). The U.S. share of world oil demand, and consequently its market leverage, is declining as the rest of the world increases its demand.
Figure 4. World Petroleum Consumption by Region, 1980 – 2010
Source: U.S. Energy Information Administration, International Energy Statistics
U.S. domestic crude production is up because of tight oil – extraction of conventional light crude using the unconventional drilling technique known as hydraulic fracturing – and other unconventional supplies. In hydraulic fracturing, or “fracking” wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the oil is released. Additionally, carbon dioxide injected into oil wells, known as carbon dioxide enhanced oil recovery, is helping to sustain oil production in otherwise declining oil fields and currently accounts for 6 percent of U.S. oil production; this practice is constrained by limited supplies of carbon dioxide.
At the same time, U.S. petroleum demand has fallen steadily since it peaked in 2005. Demand is not expected to exceed 2005 levels until after 2035, if at all, largely because of two key domestic policies: (1) renewable fuel standards requiring the displacement of petroleum-based gasoline with biofuels, and (2) new fuel economy standards for light-, medium-, and heavy-duty vehicles.
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Oil prices have historically been volatile and this is likely to continue due to supply disruptions motivated by world politics and shifts in global supply and demand. Because the oil market is global, any significant conventional oil find anywhere in the world or any technological breakthrough with regard to the recovery of unconventional oil sources that has the ability to meaningfully augment global supply, has the potential to push oil prices down. The prospects of finding a large conventional oil field within the United States are low, but off-shore (non-conventional) deep-water drilling in the Gulf of Mexico as well as on-land and off-shore regions in Northern Alaska hold the greatest potential. With a small amount of proven reserves relative to the global quantity, the United States is a price-taker. However, dramatic changes in U.S. consumption, as evidenced by the economic downturn in 2009 can affect world oil prices.
Figure 5. Crude Oil Spot Prices 1995 - 2012
Source: U.S. Energy Information Administration, Petroleum Data
By reducing its demand for oil, the United States can make itself more resilient to oil price shocks, and by increasing domestic production, the United States can reduce its trade deficit. The United States has numerous options for further reducing its oil demand, including additional tightening of fuel economy standards and shifting to alternative fuels (see our 2011 report: Reducing Greenhouse Gases from U.S. Transportation). Also, an estimated 35-50 billion barrels of economically recoverable oil could be produced in the United States using currently available enhanced oil recovery technologies and practices, or potentially more than twice the country’s proven reserves; enhanced oil recovery using carbon capture is the only domestic oil supply option that also decreases GHG emissions.
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Center Resources (Publications, blogs, BELC companies, Techbook entries)
- The Enhanced Oil Recovery (EOR) Initiative
- Greene & Plotkin (2011), Reducing Greenhouse Gas Emissions from U.S. Transportation
- Burbank & Nigro (2011), Saving Oil and Reducing Greenhouse Gas Emissions through U.S. Federal Transportation Policy
- Joel Bluestein (2010), Coverage of Greenhouse Gas Emissions from Petroleum Use under Climate Policy
External Resources (datasets, publications, websites); should be as recent as possible
- Environmental Protection Agency, “GHG Inventory Report, 1990-2010”
- International Energy Agency, "Oil Market Report"
- BP’s Statistical Review of World Energy 2011
- Shell’s Enhanced Oil Recovery webpage
- Congressional Research Service, “The U.S. Trade Deficit, the Dollar, and the Price of Oil,” J. Jackson, March 14, 2011
- EIA, “Oil: Crude and Petroleum Products Explained”
- Resources for the Future, “The Role of Oil in the U.S. Economy: Insights from a Veteran Observer,” Winter/Spring 2011
- In the United States, coal is the third largest primary energy source, accounting for 20.8 percent of all energy consumed in 2010 with the electric power sector accounting for 92 percent of U.S. coal consumption.
- Coal is still a major source of energy for U.S. electricity generation, but its role is declining in favor of natural gas and other energy sources due to low natural gas prices, state renewable energy standards and environmental regulations.
- With the highest carbon content of all the fossil fuels, carbon dioxide emissions from coal combustion represented 28.3 percent of total U.S. greenhouse gas emissions in 2010.
- Globally, coal is one of the most widely distributed energy resources with recoverable reserves in nearly 70 countries. The U.S., China, and India are the top producers and consumers of coal. Worldwide, coal supplies 26.6 percent of energy use and is responsible for 43.1 percent of global CO2 emissions.
- Most of the coal produced is consumed in the country in which it was mined. International trade accounts for only 16 percent of coal consumption worldwide; this share is expected to increase to 17 percent over the next 25 years.
- Compared to natural gas, the price of coal for electric power plants in the United States has remained relatively stable since the 1980s and expected to remain so over the next 25 years.
- Under potential climate policies, the development and success of low-emission technologies such as carbon capture and storage or other pollution control devices will be key in order to reduce the impact of continued to coal use.
In 2010, 92 percent of coal consumed in the U.S. was used for 45 percent of total U.S. electric power generation. The remaining 8 percent was consumed for industrial purposes, including steel and cement manufacturing. Worldwide, electric power generation was also the largest consumer of coal. In 2009, the electricity sector consumed 62 percent, while global industrial coal consumption was approximately 32 percent. The remaining 6 percent was used in the commercial and residential sectors.
Coal is a brownish to black sedimentary rock; it is formed under high temperature and pressure from plants and other organic matter that lived millions of years ago through a geologic process known as coalification. There are four main types of coal, classified according to the amount of available heat energy. The amount of carbon, hydrogen, and oxygen in the coal are the main factors that determine the amount of heat released during combustion. The carbon content determines the amount of CO2 emissions from each type of coal.
Table 1: Types of Coal and its Uses
Location of Deposits
% US Production (2010)
Black and brittle with a glassy appearance; usually the oldest type; sometimes called “hard coal”
Electric power, some space heating, industrial uses
Nearly 15,000 BTUs per pound
Softer than anthracite and sometimes called “soft coal”; low moisture content; 100 to 300 million years old
Most common type used for electric power, production of coke for steel industry
10,500- 14,500 BTUs per pound
East of the Mississippi; WV, KY and PA are top producers
Harder and darker than lignite; dates back at least 100 million years; lower sulfur content than bituminous coal
Electric power, industrial uses
8,300-13,000 BTUs per pound
West of the Mississippi; Wyoming is the top producer
Soft, crumbly and light-colored; relatively young; high moisture and ash content
Electric power, production of synthetic gas and liquids
4,000- 8,300 BTUs per pound
Mainly in Texas and North Dakota
Source: U.S. Energy Information Agency, “Coal Explained,” 2012
Bituminous coal is the most abundant type of coal in the United States and it is divided into two sub-types, according to end use. The first, steam or thermal coal, is used mainly for electricity generation, while the second, coking or metallurgical coal, is used in steel production. As a general rule, bituminous coal with its higher heat content coal is more desirable for electric power generation. Sub-bituminous coal from Wyoming’s Powder River Basin has a much lower sulfur content, which makes it an attractive fuel option because of regulatory limits on sulfur dioxide emissions.
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Depending on the geology of the coal formation, there are two main methods of extracting coal, surface and underground. Surface mining is used when coal is deposited less than 200 feet below the surface, while underground mines are suitable for coal formations several hundred feet below the earth. The recovery ratio of a coal deposit can be more than 90 percent for surface mines, while less than 40 percent for underground mines.
After the coal is mined, it is sent to a preparation plant for minimal processing and then transported to end-users through rail, barge, and/or truck. In the United States, rail is the primary mode of transportation for long-haul shipments of coal. Nearly all the coal mined in Wyoming, for instance, is sent via rail directly to power plants in the eastern United States. Trucks are used mainly for short hauls from mines to nearby electricity and industrial plants.
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A large number of environmental problems are associated with the production and combustion of coal. One significant impact is acid mine drainage, where acidic run-off is formed through a chemical reaction between water and sulfur-bearing rocks. This run-off contaminates creeks and rivers, and, because it diffuses easily, can be difficult to contain. Another significant impact is the practice of mountaintop mining. As the tops of mountains are removed to reveal coal seams, the sediment and waste becomes valley fill, impacting water quality and resulting in the loss of headwater ecosystems, or the species and environmental processes that are native to river sources. The U.S. Environmental Protection Agency uses the best-available science and incorporates feedback from the public and key stakeholders to provide guidance to protect water quality and people’s health regarding abandoned mines and mountaintop removal mining, among other things.
In terms of greenhouse gases, mining can result in the direct release of methane (which has a global warming potential 23 times higher than CO2, but only persists in the atmosphere for 12 – 17 years), particularly from underground mines. In 2010, methane emissions from U.S. coal mining were 1.1 percent of overall U.S. greenhouse gas emissions. The EPA estimates that coal mine methane contributes 8 – 10 percent of human-made methane emissions worldwide.
Table 2: Global Methane Emissions from Coal Mining
Surface mining %
Underground mining %
20 (NSW 59)
Source: U.S. Environmental Protection Agency, 2005
Carbon dioxide emissions from coal combustion for electric power and industry were responsible for 28.3 percent of total U.S. greenhouse gas emissions in 2010. Moreover, combustion emits common air pollutants, such as sulfur dioxide, nitrogen oxides, particulate matter, and mercury as well as other heavy metals. These air pollutants have adverse effects on both public health and the environment. Consequently, many but not all coal plants use a variety of technologies, such as scrubbers, to reduce most of the pollutants from combustion emissions. Some governments and companies are developing carbon capture and storage technologies that will capture, transport and store CO2 emissions underground. For more information, see Climate Techbook: Carbon Capture and Storage.
Additionally, coal combustion residuals, commonly referred to as coal ash, contain a broad range of metals, including arsenic, selenium and cadmium; however, the EPA considers the amounts of chemicals leached from these residuals to be non-hazardous. Coal combustion residuals are one of the largest waste streams generated in the United States, and must be managed to prevent environmental impacts such as the Kingston, Tennessee spill in 2008. Finally, heavy water usage for coal-fired power generation can stress aquifers and watersheds, and in many instances, water must be cooled to near ambient levels before being returned to the surroundings to protect ecosystems.
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The U.S. Energy Information Administration estimated global coal reserves at 948 billion short tons in 2008. At forecast consumption rates, these reserves are expected to last 126 years. The BP Statistical Review of World Energy gives similar numbers for global reserves; however, other estimates predict much lower numbers, closer to 400 billion tons.
Figure 1: McKelvy Diagram for Coal or Gas Resources
Source: McKelvy, V.E. 1972. “Mineral Resource Estimates and Public Policy.” American Scientist 60 (1): 32-40
Although coal deposits are distributed throughout the world, they are concentrated in the United States, Russia, China, and Australia.
Figure 2: Recoverable Coal Reserves by Country
For the United States, estimated recoverable reserves were 259 billion short tons as of January 1, 2011. Of this, recoverable reserves at producing mines were 17.9 billion tons; this reflects the working inventory at producing (active) mines.
Figure 3: Coal-Bearing Areas in the United States
Source: National Energy Technology Laboratory, 1983.
Domestic coal reserves are concentrated in several regions of the country. The majority of the estimated reserves are bituminous (53.1 percent), mainly found east of the Mississippi River. The next most common, sub-bituminous (36.6 percent) is found primary west of the Mississippi. Lignite deposits, which account for 8.8 percent of estimated reserves, are found in Montana, Texas, and North Dakota. Anthracite reserves are only about 1.5 percent and are concentrated in northeastern Pennsylvania.
In 2010, world coal production was 7,985 million short tons. China, the United States, and India are the top three coal producers. Since 1985, China has surpassed the United States in annual coal production. In 2010, China produced 3,522 million short tons of coal, more than 3.2 times the amount of coal produced in the United States.
In total, domestic coal production has increased approximately 5 percent since 1990 to 1,083 million short tons in 2010, but this increase obscures the fact that in some areas of the country, production has gone down even as it has gone up in other regions. In the Interior and Western regions, production increased, while production in the Appalachian Region continued to decrease, remaining at a near 50-year low. The top five coal producing states are:
- Wyoming (41 percent of U.S. total) is part of the Western region, producing 86 percent of the total amount of sub-bituminous coal in the United States.
- West Virginia (12 percent of U.S. total) is in the Appalachian region and produces only bituminous coal.
- Kentucky (10 percent) is split into two regions, both of which produce only bituminous coal.
- Pennsylvania (5 percent) is in the Appalachian region and the country's only producer of anthracite.
- Montana (4 percent) is in the Western region and produces only sub-bituminous coal.
There were approximately 1,285 mines in operation in the United States in 2010. The majority of these mines (61 percent) were surface mines and responsible for 69 percent of domestic coal production in 2010. Surface mining is much more prevalent in the western United States, where about 90 percent of the coal is extracted from surface mines.
Approximately 7,994 million short tons of coal were used worldwide in 2010. Three quarters of the world's coal is consumed by the top five users – China, United States, India, Germany, and Russia. As a region, Asia uses almost two thirds of global coal supplies. Coal usage accounts for approximately 27 percent of world energy consumption. Industrial consumers are responsible for about 32 percent of coal consumption worldwide, while the electricity sector uses about 62 percent.
In 2010, total coal consumption in the United States was 1,048.3 million short tons, which represented an increase of approximately 5 percent from 2009. While 2010 coal consumption increased, this number was more than 6 percent below 2008 levels.
The electric power sector has been the main driver of increased domestic coal consumption. However, the trend (figure 5) is flattening due to a number of factors. First, the recession, which began in late 2007, reduced overall economic activity and the demand for coal in the electricity and industrial sector fell. In 2009, the economy began to grow again, albeit slowly. During this period, very low natural gas prices (which are expected to continue until at least the end of this decade), coupled with under-utilized generating capacity at efficient combined cycle power plants, made natural gas the economic fuel choice for baseload power in the U.S. electric power sector. That further eroded demand for coal. At the same time, EPA rules affecting coal plant emissions have come into force, contributing to coal plant retirements. Finally, state energy portfolio standards have increased the quantity of available renewable power sources; wind now makes up approximately 3 percent of the annual electric generation mix in the U.S.
Figure 4. Recent Trend in U.S. Coal Consumption, 1990 – 2010
Figure 5. U.S. Coal Consumption, 1949 – 2010
Over the next 25 years, the EIA predicts that China will make up more than half of the world coal consumption. Increased use of coal in develpoping economies, including China, accounts for all of the projected growth in coal use until 2035, continuing a trend that began in the early 2000s (figure 6). Total coal production in developing economies of 160.8 quadrillion Btu in 2035 is expected to be more than three times higher than total coal production in developed nations.
Figure 6: Global Coal Consumption and Forecast, 1980-2035
Over the next 25 years, the EIA forecasts that coal use in the United States will increase 0.2 percent annually, from 2009 to 2035. Projected growth is due to increases in domestic coal consumption for use in power plants and for the production of synthetic fuels. However, the portion of electricity from coal-fired generation is predicted drop from 42 to 39 percent, due to increases in electricity generation from natural gas, nuclear and renewables. Note that total electricity generation is forecast to increase 0.8 percent annually, from 2009 to 2035.
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Most coal is consumed in the country in which it was mined, with only about 16 percent of total overall coal consumption traded internationally in 2010. Coal trade is differentiated by the type of coal, either steam coal (used in power plants) or coking coal (used in industrial production). Historically, trade in steam coal has increased at an average rate of 7 percent per year over the past 20 years, and for coking coal, about 2 percent annually. U.S. coal exports, chiefly Central Appalachian coal, made up 6.9 percent of the global export market in 2010, up from 5.5 percent in 2009.
Table 3. Top Five Exporting and Importing Countries (Million Short Tons)
Because transportation costs are a large share of the total coal price, international trade in coal is split into two main regions: the Atlantic, made up of Western Europe, and the Pacific, composed of importing countries in Asia, which accounts for the majority of world coal trade. These markets overlap when prices are high, with South Africa as a point of convergence between the two.
Figure 7: Inter-regional Coal Trade Flows (Metric Tons)
Australia is the largest exporter of both steam and coking coal; most of its coal goes to Asia. Under forecast consumption rates, international coal trade is predicted to grow at an average annual rate of 1.4 percent over the next 25 years. Because the largest increases in consumption are forecast to occur in India and China, which meet most of the increase in their coal demand with domestic supply rather than imports, the share of coal trade as a percentage of global coal consumption grows modestly to 17 percent in 2035. Australia and Indonesia are expected to continue as the leading suppliers of coal over the next 25 years, while Asia is forecast to remain the largest importer of coal.
In its International Energy Outlook 2011, the EIA projects that total annual U.S. coal exports will rise from about 83 million short tons in 2010 to 143 million short tons in 2035 (from nearly 8 percent to 13 percent of 2010 U.S. annual production levels), buoyed by the increase in Asian coal demand. Because U.S. coal export facilities are located primarily in the east, the United States is currently at a distinct geographic disadvantage relative to Australia and Indonesia. Higher transportation costs associated with shipping coal from the eastern United States to Asian markets historically has meant that U.S. coal exports cannot compete economically in that region. According to preliminary data, however, in 2010 the United States saw growth in its coking coal exports to Asia at levels unseen in the recent past, estimated at 13 million tons in the third quarter of 2010, compared with 4 million tons in the third quarter of 2009.
The domestic price of coal is a function of supply and demand, coal type, and mining method used. Generally, lignite is the least expensive, and anthracite the most expensive. Surface-mined coal is usually lower in price than underground-mined.
Figure 8: U.S. Regional Coal Spot Prices
Transportation can be a significant portion of the delivered coal price. In 2010, transportation costs on average accounted for approximately 20 percent of the total delivered price to power plants in the United States. Compared to natural gas, the price of coal for electric power plants in the United States has remained relatively stable since the 1980s (with the notable exception of 2008, when many commodities spiked simultaneously).
Over the next 25 years, the domestic price of coal is not expected to increase significantly (0.2 percent per year over the entire projection period). In comparison, natural gas prices are expected to increase by approximately 2.1 percent per year.
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Because of its high-energy content, low cost per unit of energy, and abundant worldwide reserves, coal is the least-cost energy source for both developed and developing countries. Estimated worldwide reserves, if consumed at forecast consumption levels, are expected to last 126 years. Although supplies of coal are substantial, other factors may limit its use as an energy source.
In the United States, proposed and upcoming regulations by the EPA, as well as any future action on greenhouse gas emissions, will impact coal power plants and future coal markets. For example, in July 2011, the U.S. EPA issued guidance on water quality standards from surface coal mining in the Appalachian Region. Additionally, in February 2012 the agency published the mercury and air toxic standard rule, which is designed to reduce the emissions of harmful heavy metals as well as sulfur dioxide and fine particle pollution from power plants. Many electric generating units are already compliant with these rules; however, existing sources will have up to four years if they need it to comply. Also, the EPA in July 2011 issued the Cross-State Air Pollution Rule, which sets new standards for controls on power plants that cause much of the oxides from nitrogen and sulfur dioxide (which react and become ozone and fine particulate matter) that travel downwind and across state lines. Utilities have already announced the retirement of older, inefficient and infrequently used coal power plants in response to these rules. Additionally, in March 2012 the EPA released new performance standards for new electric power plants under the Clean Air Act. Under the proposed standard, all new power plants would need to match the greenhouse gas emissions performance currently achieved by highly efficient natural gas combined cycle power plants, that is, emit less than 1,000 pounds of CO2 per megawatt/hour. If implemented, this rule would effectively bar any new coal power plant from being built in the U.S. unless it implemented carbon capture and storage technology; even emissions from a state-of-the-art, integrated gasification combined cycle coal power plant are in excess of 1,600 pounds of CO2 per megawatt/hour.
Worldwide, coal use accounts for 43.1 percent of global CO2 emissions. Reducing these emissions, in the context of increasing use in growing economics, will be a challenge. Development of low-carbon technologies and complementary government policies to drive the deployment of these technologies will be key factors enabling the use of coal in the future.
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- Climate Techbook: Carbon Capture and Storage
- Mercury and Air Toxic Standard (MATS) rule
- Cross-State Air Pollution Rule (CSAPR)
- New Source Performance Standards (NSPS) for emissions of CO2
External Resources (datasets, publications, websites);
- Environmental Protection Agency, “GHG Inventory Report, 1990-2010”
- IEA, “Key World Energy Statistics”
- EIA, “Coal Explained”
- EIA Annual Coal Report
- World Coal Association
- In the United States, renewable energy for electric power, transportation, industrial, residential and commercial purposes is the fastest-growing energy source, increasing 32 percent from 2000 to 2010 from 6.1 to 9.0 quadrillion British Thermal Units (Btus).
- In 2011, renewable energy was responsible for 12.7 percent of net U.S. electricity generation with hydroelectric generation contributing 7.9 percent and wind generation responsible for 2.9 percent of this total.
- Globally, renewable energy was responsible for approximately 19.5 percent of electricity generation with hydro generation accounting for 16.2 percent of the total in 2009.
- The U.S. Energy Information Agency projects that solar power will be the fastest-growing source of renewable energy in the United States with annual growth averaging 11.7 percent in the period from 2010 to 2035. In 2010, solar generation accounted for 0.4 percent of total renewable generation. In 2035, this is projected to climb to 3 percent.
- In 2010, renewable ethanol and biodiesel transportation fuels made up 23 percent of total U.S. renewable energy consumption, up from just 12 percent in 2006.
Renewable energy comes from sources that can be regenerated or naturally replenished. The main sources of renewable energy are:
Renewable energy is used for electric power generation, space heating and cooling, and transportation fuels. All sources of renewable energy are used to generate electric power. In addition to generating electricity, geothermal steam is used directly for heating and cooking. Biomass and solar sources are also used for space and water heating. Ethanol and biodiesel are the renewable transportation fuels with gaseous biomethane also fueling transport to a much lesser extent.
Renewable energy sources are considered to be zero (wind, solar, and water), low (geothermal) or neutral (biomass) with regard to greenhouse gas emissions during their operation. A neutral source has emissions that are balanced by the amount of carbon dioxide absorbed during the growing process. However, each source’s overall environmental impact depends on its overall lifecycle emissions, including manufacturing of equipment and materials, installation as well as land-use impacts.
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Water power captures the energy of flowing water in rivers, streams and waves to generate electricity. Conventional hydropower plants can be built in rivers with no water storage (known as “run-of-the-river” units) or in conjunction with reservoirs that store water, which can be used on an as-needed basis. As water travels downstream, it is channeled down through a pipe or other intake structure in a dam (penstock). The flowing water turns the blades of a turbine, generating electricity in the powerhouse, located at the base of the dam.
Figure 1. Hydroelectric Power Generation
Source: Environment Canada, 2012
Large conventional hydropower projects currently provide the majority of renewable electric power generation. With 970 gigawatts (GW) of global capacity, hydropower produced an estimated 3,400 terawatt hours (TWh) of total global electricity in 2011. Note that in 2009, total global electricity generation was 18,979 TWh. Hydropower operational costs are relatively low, and it generate little to no greenhouse gas emissions. The main environmental impact is to local ecosystems and habitats; a dam to create a reservoir or divert water to a hydropower plant changes the ecosystem and physical characteristic of the river.
The United States is the fourth-largest producer of hydropower after China, Canada and Brazil. In 2011, a much wetter than average year in the U.S. Northwest, the United States generated 7.9 percent of its total electricity from hydropower. The quantity of electricity generated each year depends on the amount of precipitation that falls over a particular area.
Small hydropower, generally less than 10 megawatts (MW), and micro-hydropower (less than 1 MW) are less costly to develop and have a lower environmental impact than large conventional hydropower projects. In 2011, the total amount of small hydro installed worldwide was 106 GW – China had the largest share at 55.3 percent, followed by India at 9 percent and the United States at 6.9 percent. Many countries have renewable energy targets that include the development of small hydro projects. In the United States, the Federal Energy Regulatory Commission (FERC) approved more than 50 project permits in 2009.
Hydrokinetic electric power, including wave and tidal power, is a form of unconventional hydropower that captures energy from waves or currents and does not require dam construction. These technologies are in various stages of research, development and deployment. In 2011, a 254 MW tidal power plant in South Korea began operation, doubling the global capacity to 527 MW.
Low-head hydro is a commercially available source of hydrokinetic electric power that has been used in farming areas for more than 100 years. Generally, the capacity of these devices is small, ranging from 1kW to 250kW.
Pumped storage hydropower plants use inexpensive electricity (typically overnight during periods of low demand) to pump water from a lower-lying storage reservoir to a storage reservoir located above the power house for later use during periods of peak electricity demand. Since this technology uses more electricity than it generates, it is not considered to be renewable energy. Note that it is economical to do this since the revenues that a generator receives during times of peak electricity generation far exceed the costs that they pay to pump the water during times of low electricity demand.
Figure 2. Pumped Storage Power Generation
Source: U.S. Geological Survey, 2012
Wind power harnesses the energy generated by the movement of air in the earth’s atmosphere to drive electricity-generating turbines. Although people have used wind power for hundreds of years, modern turbines reflect significant technological advances over early windmills and even over turbines from just 10 or 20 years ago. Generating electric power using wind turbines creates no greenhouse gases, but since a wind farm includes dozens or more turbines, widely-spaced, it requires thousands of acres of land. For example, Lone Star is a 200 MW wind farm located in Texas on approximately 36,000 acres.
After hydropower, wind was the next largest renewable energy source used for power generator with 238 GW of global capacity at the end of 2011. Capacity is the maximum amount of electicity that can be generated when the wind is blowing at sufficient levels for a turbine. Because the wind is not always blowing, wind farms do not always produce as much as their capcity. With more than 62 MW, China had the largest installed capacity of wind generation in 2011, and the United States with 47 GW had the second-largest capacity; Texas, Iowa, California, Minnesota and Illinois were the top five wind power producing states.
Average turbine size has been steadily increasing over the past 30 years. Today, new onshore turbines are typically in the range of 1.5 – 3.5 MW. The largest production models, designed for off-shore use, are capable of generating more than 7.5 MW; some innovative turbine models under development are expected to generate more than 15 MW in offshore projects in the coming years. Due to higher costs and technology constraints, off-shore capacity, approximately 3 GW in 2010, is only a small share of total installed wind generation capacity. For more information on wind power, see Climate TechBook: Wind.
Figure 3. Size and Power Evolution of Wind Turbines Over Time
Solar power harnesses the sun’s energy to produce electricity as well as solar heating and cooling. Solar energy resources are massive and widespread, and they can be harnessed anywhere that receives sunlight. The amount of solar radiation, also known as insolation, reaching the earth’s surface every hour is more than all the energy currently consumed by all human activities each year. A number of factors, including geographic location, time of day, and current weather conditions, all affect the amount of energy that can be harnessed for electricity production or heating purposes.
Solar energy can be captured for electricity production using solar photovoltaics and concentrating solar power. A solar or photovoltaic cell converts sunlight into electricity using the photoelectric effect. Typically, photovoltaic is found on the roofs of residential and commercial buildings. Concentrating solar power uses lenses or mirrors to concentrate sunlight into a narrow beam that heats a fluid, producing steam to drive a turbine which generates electricity. Concentrating solar power projects are larger-scale than residential or commercial PV and are often owned and operated by electric utilities.
Figure 4. Concentrating Solar Power
Source: NextEra Energy, 2012
Solar hot water heaters, typically found on the roofs of homes and apartments, provide residential hot water by using a solar collector, which absorbs solar energy, that in turn heats a conductive fluid, and transfers the heat to a water tank. Modern collectors are designed to be functional even in cold climates and on overcast days.
Electricity generated from solar energy emits no greenhouse gases. The main environmental impacts of solar energy come from the use of some hazardous materials (arsenic and cadmium) in the manufacturing of PV and the large amount of land required, hundreds of acres, for a utility-scale solar project. For more information on solar energy, see Climate TechBook: Solar.
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Biomass energy sources are used to generate electricity, provide direct heating and can be converted into biofuels as a direct substitute for fossil fuels used in transportation. Unlike intermittent wind and solar energy, biomass can be used continuously or according to a schedule. Biomass is derived from wood, waste, landfill gas, crops and alcohol fuels. Traditional biomass, including waste wood, charcoal and manure has been a source of energy for domestic cooking and heating throughout human history. In rural areas of the developing world, it remains the dominant fuel source. Globally in 2010, traditional biomass accounted for about 8.5 percent of total energy consumption. The growing use of biomass has resulted in increasing international trade in biomass fuels in recent years; wood pellets, biodiesel, and ethanol are the main fuels traded internationally.
In 2011, global biomass electric power capacity stood at 72 GW. In 2010, the United States had 11.4 GW of installed biomass-fueled electric generation capacity. In the United States, most of the electricity from wood biomass is generated at lumber and paper mills using their own wood waste; in addition, wood waste is used to generate the heat for drying wood products and other manufacturing processes. Biomass waste is mostly municipal solid waste, i.e., garbage, which is burned as a fuel to run power plants. On average, a ton of garbage generates 550 to 750 kWh of electricity. Landfill gas contains methane that can be captured, processed and used to fuel power plants, manufacturing facilities, vehicles and homes. In the United States, there is currently 1.7 GW of installed landfill gas-fired generation capacity at 400 projects.
In addition to landfill gas, biofuels can be synthesized from dedicated crops, trees and grasses, agricultural waste and algae feedstock; these include renewable forms of diesel, ethanol, butanol, methane and other hydrocarbons. Corn ethanol is the most widely used biofuel in the United States. Roughly 40 percent of the U.S. corn crop was diverted to the production of ethanol for gasoline in 2010, up from 20 percent in 2006. Gasoline with up to 10 percent ethanol (E10) can be used in most vehicles without further modification, while special flexible fuel vehicles can use a gasoline-ethanol blend that has up to 85 percent ethanol (E85).
Closed-loop biomass ,where power is generated using feedstocks grown specifically for the purpose of energy production, is generally considered to be carbon dioxide neutral because the carbon dioxide emitted during combustion of the fuel was previously captured during the growth of the feedstock. While biomass can avoid the use of fossil fuels, the net effect of biopower and biofuels on greenhouse gas emissions will depend on full lifecycle emissions for the biomass source, how it is used, and indirect land-use effects. For more information, see Climate Techbook: Biofuels and Biopower. Overall, however, biomass energy can have varying impacts on the environment. Wood biomass, for example, contains sulfur and nitrogen, which yield air pollutants sulfur dioxide and nitrogen oxides, though in much lower quantities than coal combustion.
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Traditional geothermal energy exploits naturally occurring high temperatures, located relatively close to the surface of the earth in some areas, to generate electric power and for direct uses such as heating and cooking. Geothermal areas are generally located near tectonic plate boundaries, where there are earthquakes and volcanoes. In some places, hot springs and geysers naturally rise to the surface. These have been used for bathing, cooking and heating for centuries. At least 78 countries used direct geothermal power in 2011.
Generating geothermal electric power typically involves the drilling of well, perhaps a mile or two in depth, in search of rock temperatures in the range of 300 to 700°F. Water is pumped down this well, where it is reheated by hot rocks. It travels through natural fissures and rises up a second well as steam, which can be used to spin a turbine and generate electricity or it can be used for heating or other purposes. Note that drilling a suitable injection well is by no means a certain task; several wells may have to be drilled before a suitable one is in place and the size of the resource cannot be confirmed until after the drilling takes place. Additionally, some water is lost to evaporation in this process, so new water is added to maintain the continuous flow of steam. Like biopower and unlike intermittent wind and solar power, geothermal electricity can be used continuously. Note that very small quantities of carbon dioxide trapped below the earth’s surface are released during this process.
Figure 5. Geothermal Power Station
Source: BBC Science
Globally, geothermal provided an estimated 205 TWh in 2011, one third in the form of electricity (with an estimated 11.2 GW of capacity) and the remaining two-thirds in the form of heat. Note that in 2009, total global electricity generation was 18,979 TWh. In 2011, the 16.7 billion kWh of geothermal electricity generated in the United States constituted 8.6 percent of the non-hydroelectric, renewable electricity generation, but only 0.4 percent of total electricity generation. The same year, five states generated electricity from geothermal energy , California, Hawaii, Idaho, Nevada and Utah. Of these, California accounted for 80 percent of this generation. For more information, see Climate TechBook: Geothermal.
Enhanced geothermal systems use advanced, often experimental drilling and fluid injection techniques to augment and expand the availability of geothermal resources. They are being studied by the U.S. Department of Energy. For more on this topic (see Climate TechBook: Enhanced Geothermal Systems).
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Figure 6. Global Average Annual Growth Rates of Renewable Energy Capacity and Biofuels Production, 2006 – 2011
There are several factors that determine which renewable technologies are adopted. These include market drivers (cost, diversity, proximity to demand or transmission, resource availability, and others), policy decisions (tax credits and renewable portfolio standards) as well as specific regulations. At least 118 countries, more than half of which are developing, had renewable energy targets in place in 2012, and at least 109 countries had renewable power policies.
U.S. Electricity Sector
All renewable energy sources are used to generate electric power. When selecting new electricity capacity additions utility planners often look at levelized costs as a convenient summary measure of the overall competitiveness of different technologies. Total system levelized costs here (Figure 7) do not include policy-related factors like tax credits, and assumptions about future fuel prices and financing costs in particular can significantly affect these cost projections. Also, dispatchable technologies, i.e., those that can be controlled by an operator, are more desirable than non-dispatchable or intermittent technologies.
Table 1. U.S. Average Levelized Costs (2010 $/MWh) for Plants Entering Service in 2017
Capacity Factor (%)
Levelized Capital Cost
Variable O&M (Including fuel)
Total System Levelized Cost
Advanced Coal with Carbon Capture & Storage (CCS)
Natural Gas Fired
Conventional Combined Cycle (CC)
Advanced CC with CCS
Conventional Combustion Turbine (CT)
Source: U.S. Energy Information Agency Annual Energy Outlook. June 2012
In the absence of policy mandates and incentives, a utility planner would be inclined to select the least-cost, dispatchable generation technology, which today is a natural gas-fired combined cycle. Additionally, planners often consider the mix or diversity of the generation under their control, so as to minimize exposure to any one particular technology. Also, planners must consider the environmental impacts and regulatory rules, e.g. land and water use, ecosystems, wild-life impacts and pollution mitigation.
An renewable portfollio standard is a state mandate, which specifies that electric utilities deliver a certain amount of electricity from renewable or alternative energy sources by a given date. State standards range from modest to ambitious, and qualifying energy sources vary. Some states also include "carve-outs" (requirements that a certain percentage of the portfolio be generated from a specific energy source, such as solar power) or other incentives to encourage the development of particular resources. Although climate change may not be the prime motivation behind these standards, the use of renewable or alternative energy can deliver significant greenhouse gas reductions. Increasing a state’s use of renewable energy brings other benefits as well, including job creation, energy security, and cleaner air. Most states allow utilities to comply with the renewable portfolio standard through tradeable credits. These credits can be sold in addition to the electricity generated to gain additional revenues for the utilities.
In states where a renewable portfolio standard exists, utilities must consider renewable technologies that satisfy this requirement. Cost is typically a key driver of the selected technology, but intermittency and resource availability have to be taken into account. In the case of wind, it is a lower-cost renewable technology, but it is intermittent, i.e., the wind is not always blowing hard enough to generate electricity. Moreover, many onshore locations in the United States (Figure 8), particularly in the east and south are not well-suited for wind generation. In these areas, many counties have biomass resources (Figure 10) greater than 55,000 tons/year. Since biomass is not an intermittent resource (Figure 7), it might be an attractive option to meet a renewable portfolio standard requirement. Note that roughly 25,000 to 45,000 tons of biomass is needed to support 5 MW of generation for one year at 70 percent utilization rate (~30,000 MWh/year), depending on the condition and type of biomass. Note also that wind’s intermittency issue can be lessened to an extent by grid connecting individual wind farms from many geographically diverse areas, so if the wind is not blowing in one area, it is likely blowing in others.
At the federal level, there are two tax credits that have served to encourage the adoption of renewable energy sources: the production tax credit and the investment tax credit. First enacted in 1992 and subsequently amended, the production tax credit is a corporate tax credit available to a wide range of renewable technologies including wind, landfill gas, geothermal and small hydroelectric. For wind, geothermal and closed-loop biomass, the utility receives a 2.2 ¢/kWh ($22/MWh) credit for all electricity generated during the first 10 years of operation. For wind, with an average total system levelized cost of $96/MWh (Figure 7), the production tax credit represents a 23 percent cost reduction. The investment tax credit is earned when qualifying equipment, including solar hot water, photovoltaics, small wind turbines, is placed into service. The credit functions to reduce installation costs and shorten the payback time of these technologies. In addition to these federal incentives, states offer added incentives, making renewables even easier to implement from a cost perspective.
U.S. Transportation Sector
Biofuels have been gaining attention as a way to lessen dependence on petroleum-based fuels and reduce greenhouse gas emissions. To that end, the United States has adopted a renewable fuel standard.
The Energy Policy Act of 2005 created a Renewable Fuel Standard in the United States that required 2.78 percent of gasoline consumed in the U.S. in 2006 to be renewable fuel. With the Energy Independence and Security Act of 2007, Congress created a new Renewable Fuel Standard, which increased the required volumes of renewable fuel to 36 billion gallons by 2022 or about 7 percent of expected annual gasoline and diesel consumption above a business-as-usual scenario. For more information, see the C2ES overview: Renewable Fuel Standard.
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Renewable resource availability and location are key considerations in the adoption of renewable energy sources.
Idaho National Laboratory recently estimated that there is approximately 83 GW of mostly small hydropower available in the U.S. Pacific Northwest. While the DOE found that the untapped generation potential at existing dams in the United States that were designed for purposes other than power production, i.e., water supply and inland navigation represents 12 GW, roughly 15 percent of the current hydropower capacity.
The following maps from the DOE National Renewable Energy Laboratory depict the relative availability of renewable energy resources throughout the United States.
- Wind resources (Figure 7) are abundant in the Great Plains, Iowa, Minnesota, along the spine of Apalachian Mountains, in the Western Mountains and many off-shore locations.
- Solar photovoltaic (Figure 8) and concentrating solar power resources are the highest in the desert Southwest and diminish in intensity in a northward direction.
- The best biomass resources (Figure 9) are in the upper central plains (corn) and forests of the Pacific Northwest.
- Traditional geothermal resources (Figure 10) are concentrated in the Western United States.
Figure 7. U.S. Wind Resource Map
Source: U.S. National Renewable Energy Laboratories, 2009.
Figure 8. U.S. Photovoltaic Solar Resources
Source: U.S. National Renewable Energy Laboratories, 2008.
Figure 9. U.S. Biomass Resource
Source: U.S. National Renewable Energy Laboratories, 2008
Figure 10. U.S. Geothermal Resource
Globally, 16.7 percent of world energy came from renewable sources in 2010. A little more than one half of this was from traditional biomass sources used in residential heating and cooking in developing countries. In 2010, renewable energy accounted for 8 percent of total U.S. energy use (8 quadrillion Btu out of a total of 97.8 quadrillion Btu). In the United States, renewable energy is used across economic sectors (Figure 11).
Figure 11. U.S. Sector Demand for Renewable Energy
Renewable energy sources made up 12.7 percent of total electricity generation in 2011; hydro, wind and biomass made up the majority of U.S. renewable electricity generation (Figure 13). In the industrial sector, biomass makes up 99 percent of the renewable energy use with more than 60 percent derived from biomass wood, 32 percent from biofuels, and nearly 8 percent from biomass waste.
Figure 12. U.S. Renewable Electricity Generation (2011)
Source: U.S. Energy Information Administration, 2012.
World energy consumption is expected to grow 53 percent to 770 quadrillion Btus from 2008 to 2035 with most of this growth coming from developing countries (Figure 14). Renewables are projected to be the fastest-growing source of energy with consumption of hydroelectricity and other renewables set to increase 2.9 percent per year worldwide over the same time period.
Figure 13. Projected Total Global Energy Consumption
Renewable energy’s share of global electricity generation is forecast to increase from 19 percent to 23 percent; hydroelectric power is expected to contribute 55 percent of added renewable generation and wind is expected to contribute 27 percent. Large hydro projects are being constructed and planned in China, Canada and Brazil among others. According to the International Energy Agency, the development and market deployment of renewable energy technologies will depend heavily on government policies to make renewable energy cost-competitive.
In the United States over the next 25 years, renewable energy consumption, excluding ethanol, is expected to grow at an average annual rate of 1.6 percent, higher than the overall growth rate in energy consumption (0.3 percent per year), under a business-as-usual scenario. E85 (ethanol transportation fuel) is expected to be the fastest growing renewable energy type, growing at an average annual rate of 27 percent over the same period, but it starts from a very low base. For renewable electricity sources, solar is expected to grow the most rapidly, followed by wood and other biomass. Uncertainty about federal tax credits, fuel prices and economic growth will influence the pace of renewable energy source development.
- Renewable & Alternative Energy Portfolio Standards
- Climate Techbook:
- Renewable Fuel Standard
- Renewable Energy Policy Network for the 21st Century REN21
- EIA’s Renewable & Alternative Fuels
- INL’s Assessment of Natural Stream Sites for Hydroelectric Dams in the Pacific Northwest Region
- DOE’s An Assessment of Energy Potential at Non-Powered Dams in the United States
- IRS’s Production Tax Credit, Investment Tax Credit
- WRI’s Renewable Energy Credits Factsheet
- Hydro Green Energy
- Natural gas plays an important role in nearly every sector of the U.S. economy, constituting 25 percent of energy consumption (second only to oil) and roughly 20 percent of electricity generation in 2010.
- Combustion of natural gas emits about half as much carbon dioxide as coal and 30 percent less than oil, and far fewer pollutants, per unit of energy delivered.
- Natural gas is responsible for approximately 22 percent of U.S. greenhouse gas emissions annually, most of which (84 percent) are associated with combustion, with the remainder from venting and other fugitive methane releases (14 percent) and from flaring and removing CO2 during processing (2 percent).
- Globally, natural gas combustion accounted for 19.9 percent of the world’s CO2 emissions in 2009.
- The United States has enough natural gas to last nearly 90 years at current consumption rates (about 24.1 trillion cubic feet (Tcf) per year); the U.S. Energy Information Administration and Massachusetts Institute of Technology estimate technically recoverable reserves in excess of 2,100 Tcf.
Figure 1. Geological Formations Bearing Natural Gas
Natural gas is a naturally occurring fossil fuel consisting primarily of methane and small amounts of impurities such as carbon dioxide. It may also contain heavier liquids (also known as natural gas liquids) that can be processed into valuable byproducts including ethane, propane, butane and pentane. As illustrated in the above graphic, natural gas is found in several different types of geologic formations. Historically, natural gas has been conventionally extracted from large reservoirs and often produced in conjunction with oil. Technological advances in the areas of horizontal drilling and hydraulic fracturing have made it easier and cheaper to obtain gas from smaller unconventional sources including non-porous sand (tight sands), coal seams (coal bed methane) and most recently from very fine grained sedimentary rock called shale (shale gas), known in the industry as shale plays.
Shale gas extraction differs significantly from the conventional extraction methods. Wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the gas is released. This technique is known as hydraulic fracturing or “fracking.”
Initial assessments of 48 shale gas basins in 32 countries suggest that shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other world regions. Initial indications from a 2011 study reported 5,760 Tcf of technically recoverable shale gas resources in 32 foreign countries, compared with 862 Tcf in the United States.
Figure 2. Global Natural Gas Basins
Natural gas is used extensively in the United States, for generating electricity, for space and water heating in residential and commercial buildings, and as industrial feedstock, providing the base ingredient for such varied products as plastic, fertilizer, anti-freeze and fabrics.
Figure 3. U.S. Natural Gas Consumption by Sector
In the residential sector, almost 95 percent of natural gas is used for space and water heating, with cooking and clothes drying making up the remainder. In the commercial sector, space and water heating comprise the majority of natural gas use (62 percent), but other uses – including cogeneration (the use of natural gas to generate electricity and useful heat), also known as combined heat and power – compose one-third of natural gas usage. Bulk chemicals and refining account for more than one-third of all natural gas consumption in energy industries.
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Compared to other fossil fuels, natural gas is considered relatively “clean” because when it is burned it releases fewer harmful pollutants. Compared to coal or oil, natural gas combustion releases smaller quantities of particulate matter, nitrogen oxides, and sulfur dioxide. The combustion of natural gas also emits about half as much carbon dioxide as coal. However, methane itself is a potent GHG, more than 20 times more powerful in terms of its heat-trapping ability than CO2, though it is shorter lived in the atmosphere. Sources of methane emissions include landfills and coal mines as well as digestion by cows and other ruminant animals. Emissions from equipment leaks, process venting and disposal of waste gas streams are known as fugitive emissions.
Table 1: Fossil Fuel Emissions Levels (Pounds per Billion Btu of Energy Input)
Source: U.S. Energy Information Administration, Natural Gas Issues and Trends (1998)
Currently, natural gas-related emissions account for about 22 percent of total U.S. greenhouse gas emissions, 84 percent of which are CO2 from natural gas combustion, 14 percent comes from fugitive methane releases, and the remaining 2 percent from CO2 from flaring natural gas during field production and CO2 removal during natural gas processing. Globally, natural gas combustion accounted for 19.9 percent of the world’s CO2 emissions in 2009.
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Since 1999, U.S. proved reserves of natural gas have increased every year, driven mostly by shale gas advancements. As a result, in 2011 the United States had the fourth largest proved reserves of natural gas in the world, at 482 Tcf. Russia had the largest reserves at 1,680 Tcf, followed by Iran at 1045.7 Tcf, and Qatar at 895.8 Tcf.
In 2010, the EIA estimated that the technically recoverable resource of U.S. shale gas was 827 Tcf. In 2011, this was revised down to 482 Tcf (out of an average remaining U.S. resource base of approximately 2,543 Tcf). The decline mostly reflects changes in the assessment for the Marcellus shale (see Figure 4), from 410 Tcf to 141 Tcf, based on better data provided from the rapid growth in drilling in the Marcellus over the past two years. MIT’s mean projection estimates recoverable shale gas resources at 650 Tcf out of a resource base of 2,100 Tcf. These estimates represent nearly 90 years of domestic demand at current consumption levels of about 24.1 Tcf per year.
Natural Gas Production
Total domestic dry natural gas production in 2011 was 23.0 Tcf. This figure represents the remainder from a total gross withdrawal of 28.6 Tcf of product, after venting and flaring, removal of non-hydrocarbon gases such as CO2, removal of natural gas liquids and other losses. From 2006 to 2010, shale gas production grew at an annual rate of 48 percent. Natural gas is produced in 32 states and in the Gulf of Mexico. According to the EIA, Texas, the Gulf of Mexico, Wyoming, Louisiana, Oklahoma, Colorado and New Mexico account for 80.8 percent of U.S. production in 2010. The geography of U.S. natural gas production is changing with an increasing percentage of production coming from other states like Pennsylvania and Arkansas.
Development of fracking technology has created the present boom in natural gas production. This technology was initially funded in the 1970s through the U.S. Department of Energy and with more than 20 years of federal tax credits (1980 – 2002).
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Figure 4. U.S. Shale Plays
The U.S. natural gas pipeline network is a highly integrated transmission and distribution grid that can transport natural gas to and from nearly any location in the contiguous 48 states. Interstate and intrastate pipelines deliver natural gas to local distribution companies, directly to some large industrial end users and electricity generators, and to interconnections with other pipelines. The network consists of more than 210 pipeline systems with nearly 306,000 miles of pipe, and 1,400 compressor stations that maintain network pressure and assure continuous forward movement of supplies. To support the seasonal peaking demand of natural gas, there are 400 underground natural gas storage facilities in the pipeline network for additional winter heating demand. There are three types of underground storage facilities: depleted natural gas or oil fields, aquifers and salt caverns. Additionally, there are 49 locations where natural gas can be imported or exported at the Canadian and Mexican borders. In response to earlier expectations of natural gas import needs, there are eight liquefied natural gas (LNG) import facilities in the United States, which are now underused. With the recent increase in natural gas production, the U.S. Federal Energy Regulatory Commission (FERC) authorized one export terminal at Sabine Pass, LA in 2012 (which is expected to begin operations before 2017), and others are in various stages of the application process.
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Natural gas consumption made up a little more than 22 percent of total global energy use in 2008. The EIA estimated that world natural gas demand climbed to 112.9 Tcf in 2010, up 7.3 percent from 2009. This growth overshadows the 4 percent drop in natural gas demand experienced in 2009. According to the International Energy Agency, electric power generation remains the main driver behind global natural gas demand growth; use in this sector is estimated to have increased by 5 percent in 2010.
Natural gas use constituted about 25 percent of total U.S. primary energy consumption in 2010. Total U.S. natural gas consumption grew from 23.3 Tcf in 2000 to 24.1 Tcf in 2010. A decline in annual consumption in the industrial sector during this period was more than offset by growth in the electric power sector, which grew at an annual average rate of 3.5 percent.
Figure 5. U.S. Natural Gas Consumption by Sector, 2000 – 2010 (Tcf)
In 2010, natural gas fueled 23.9 percent of total U.S. electricity generation. From 2000 to 2010, natural gas electricity generation grew at a faster rate than total electricity generation (5.1 percent per year versus 0.8 percent per year). This growth can be attributed to a number of factors, including low natural gas prices in the early part of the decade. Additionally, gas-fired plants are relatively easy to construct, have lower emissions compared to other fossil fuels, and have lower capital costs and shorter construction times compared to coal power plants. More information about natural gas fired electricity generation can be found on the Center’s Natural Gas Techbook page.
The market for natural gas is similar to other commodities. Generally, when demand goes up, producers respond with increased exploration, drilling and production. However, significant supply increases do not happen overnight. It takes time to study the geology, acquire leases, drill wells and connect to pipelines (or build new pipelines). This expansion can take many months or years. As a result, there is often a lag in bringing new supply to market, which can cause price volatility and spikes. Conversely, oversupply (or expectations of low price), result in less exploration. Even with a lower price, many producers are reluctant to halt extraction due to the geologic characteristics of wells that make it difficult to stop and restart production. In addition, since gas is often produced along with oil or natural gas liquids, stopping the flow of natural gas means stopping the flow of oil and natural gas liquids, which may not make financial sense. Another market driver is that gas is often sold on a contractual basis, and a producer may be legally bound to produce a specific quantity of natural gas.
Natural gas markets across the world are segmented, that is, natural gas pipeline systems connect distinct regions of the world, for example, the United States is connected to Canada and Mexico while the United Kingdom is connected to the North Sea and Europe. Natural gas prices are determined within these regional markets based on the available regional supply and demand patterns. A general upward trend in world natural gas prices began in the early 2000s as demand for the product began to exceed supply. Following the global recession of 2008 – 2009 a fairly wide spread in world natural gas prices developed (Figure 6).
Figure 6: World Natural Gas Prices (USD/MMBtu)
Prices in the U.S. and Canadian markets have plummeted due to the abundant supply of North American shale gas. Asian markets have seen higher gas prices due to increasing demand in China, South Korea and Japan. Europe has also seen higher prices as a result of increased demand as well as periodic Russian supply disruptions from 2005 – 2009.
Supply and demand responses, the seasonal nature of demand (residential winter heating or summer cooling through increased electric power generation requirements), or cold weather and hurricane-driven supply disruptions, have all contributed to natural gas price volatility in the United States in the last decade (Figure 7). In 2001, several years of declining productive capacity and increasing demand resulted in a sharp winter price spike. Prices spiked again in 2005 in the wake of hurricanes Rita and Katrina, which temporarily curtailed supplies from the Gulf of Mexico. Prices remained high relative to historic norms, peaking along with other energy commodities in 2008. Since then, average annual wellhead prices in the U.S. have gone down. Two factors – an abundance of shale gas and the slow pace of economic recovery following the recession – have contributed to sustained low prices.
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Figure 7: U.S. Natural Gas Monthly Average Wellhead Prices (USD/MMBtu)
While most of the world’s gas supply is transported regionally via pipeline, global gas trade has accelerated with the growing use of liquefied natural gas. To maximize the quantity of natural gas that can be transported, the gas is liquefied at an export facility. First, the liquefaction process involves the removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons. Then, the natural gas is condensed into a liquid by cooling it to approximately -162°C (-260 °F). Liquefied natural gas takes up 1/600th the volume of natural gas in the gaseous state. Once liquefied, the LNG can be transported by tanker and regasified for use in other markets at an LNG import terminal. Between 2005 and 2010, the liquefied natural gas market grew by more than 50 percent and it now accounts for 30.5 percent of global gas trade. Global gas liquefaction capacity increased by almost 40 percent over just the past two years (Qatar completed an 80 bcf facility in 2011), and is expected to increase by an additional one-third over the next five years.
With surplus domestic supply and substantially higher prices in other regional markets, several U.S. companies have applied to the relevant agencies for permission to export liquefied natural gas with Houston-based Cheniere Energy being the first company to win approval for its Sabine Pass facility in 2012.
Prospects for U.S. liquefied natural gas exports depend significantly on the cost-competitiveness of U.S. liquefaction projects relative to those at other locations. Over much of the last decade, lower supply expectations and higher, volatile prices prompted new investments in U.S. natural gas import and storage infrastructure. Since 2000, North America’s import capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35 percent of the United States’ average daily requirement. Yet as of 2009, U.S. consumption of imported liquefied natural gas was 1.2 Bcf/day, leaving most of this capacity unused. The ability to use and repurpose existing U.S. import infrastructure—pipelines, processing plants, storage and loading facilities—will help reduce total costs relative to new facilities. While liquefied natural gas makes up a small portion of U.S. imports, it is important in other parts of the world. The majority of the gas trade in the Asia Pacific region is in the form of LNG imports to Japan, South Korea, and Taiwan from other Asia Pacific countries, Australia, and the Middle East (Figure 8).
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Figure 8: Major International Natural Gas Trade Flows (Billion Cubic Meters)
Source: BP Energy Statistics 2011
According to the EIA’s International Energy Outlook, natural gas is expected to be the world’s fastest growing fossil fuel, with consumption increasing at an average rate of 1.6 percent per year to 2035. Growth in natural gas is expected to occur in every region and is most concentrated in developing countries, where demand increases nearly three times as fast as in developed countries.
In the United States, shale gas production is expected to more than double over the next 20 years (Figure 9), and production of natural gas is expected to exceed consumption early into the next decade. As a consequence, the EIA in its 2012 Annual Energy Outlook Reference Scenario expects U.S. natural gas prices to remain below $5/MMBtu through at least 2020.
Figure 9. U.S. Natural Gas Production, 1990 – 2035 (Tcf)
The forecast of an abundance of domestic natural gas, coupled with recent regulatory actions taken by the U.S. Environmental Protection Agency (EPA) with regard to the electric power sector (Mercury rule, Cross-State Air Pollution Rule, and New Source Performance Standard for CO2 from new power plants) have led to natural gas becoming the dominant choice for planned electricity generating capacity. Moreover, the abundance of natural gas has somewhat mitigated industrial concerns about using the fuel as a feedstock to manufacture products such as plastics and fertilizers.
The rapid growth of shale gas has also increased scrutiny of the potential environmental and health effects of hydraulic fracturing. As a result, several states have taken action either to regulate hydraulic fracturing or to issue a temporary moratorium while they explore the issue further. In addition to state action, the U.S. Department of Interior proposed new rules for regulating natural gas drilling on federal lands in 2012, and the EPA has undertaken a Hydraulic Fracturing Study Plan to study the relationship between hydraulic fracturing and drinking water.
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- Natural Gas Initiative:
- Climate Techbook: Natural Gas.
- Bluestein, Joel (2008). Coverage of Natural Gas Emissions & Flows Under a GHG Cap-and-Trade Program, Pew Center on Global Climate Change.
- Claussen, Eileen. Climate Policy and Natural Gas: A Bridge to a Lower GHG Future. 2008 October 6. American Gas Association Executive Conference.
- BP’s Statistical Review of World Energy 2011
- Shell’s Natural Gas
- BPC’s Task Force on Ensuring Stable Natural Gas Markets. 2011 March 22.
- Ratner, Michael. Global Natural Gas: A Growing Resource. Congressional Research Service (CRS). R41543. 2010 December 22.
- EIA’s Natural Gas Overview
- FracFocus Chemical Disclosure Registry
- RFF’s Abundant Shale Gas Resources: Long-Term Implications for U.S. Natural Gas Markets. RFF Discussion Paper 10-41. 2010 August.
- IEA’s Natural Gas Overview
- MIT’s The Future of Natural Gas. 2011 July.
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I recently responded to a question on the National Journal blog, "Should Congress extend the production tax credit for wind energy or let it expire at year's end?"
Innovative financing program helps South Carolina homeowners save money through energy efficiency retrofits
An innovative energy-financing program has helped customers of South Carolina rural electric cooperatives to undertake energy efficiency retrofits for their homes, substantially reducing their energy use and saving money.
Through on-bill financing (OBF), customers pay back the cost of the retrofit through monthly installments on their electricity bill. This strategy helps to expand access to costly energy retrofits to low-income residents and makes the financial benefits immediately apparent. If monthly energy savings are greater than or equal to the loan repayment, then OBF will be “bill neutral” and result in the same or lower monthly electricity bills . In addition, the financial obligation of OBF is tied to the electricity meter of each house and can be passed on to subsequent owners and residents; thus, customers only pay for the energy retrofits for as long as they live there.
A preliminary review of South Carolina’s pilot program, called “Help my House,” found that the 125 participating households are projected to save an average of $400 each year after loan repayments. Energy use could be reduced by thirty-five percent, or approximately 11,000 kilowatt-hours each year. The retrofits, which included improvements to insulation, sealing, and heating, ventilation, and air-conditioning (HVAC) systems, cost an average of $7,200, with projected simple payback periods of 5.86 years. In addition, ninety-six percent of participants reported satisfaction with the efficiency installations and rated their homes as more comfortable after the retrofit.
The program was launched in 2011 by the Central Electric Power Cooperative, which supplies wholesale electricity to 20 rural South Carolina electric cooperatives, and the Electric Cooperatives of South Carolina, the co-ops’ marketing and policy partner, with support from the Environmental and Energy Study Institute. A full-scale OBF energy-efficiency program implemented by South Carolina cooperatives could save an estimated $270 million per year in electricity costs and create more than 7,000 jobs after 20 years, according to an analysis by Coastal Carolina University.
South Carolina utilities were authorized to offer OBF through the passage of Senate Bill 1096 in 2010. The bill eliminated the need for credit checks by tying the financial obligation to the meter rather than to the individual borrower, and allowed utilities to disconnect power if loan repayments are not made. Utilities in 22 other states offer OBF, with supporting state legislation in Illinois, Hawaii, Oregon, California, Kentucky, Georgia, Michigan, and New York.
In addition, “Help my House” was funded by a $740,000 loan from the U.S. Department of Agriculture’s (USDA) Rural Utility Service (RUS), which supports the development of electric, water, and telecommunications services in rural regions. This was the first time RUS funded an energy efficiency initiative, but more cooperatives around the country may follow South Carolina’s example. On July 17 USDA proposed a rule that would create a new RUS program to provide up to $250 million in loans for energy efficiency improvements. The proposed Energy Efficiency and Conservation Loan Program would allow rural electric cooperatives to provide energy efficiency retrofits, including those funded by OBF programs, audits, renewable energy systems, and more.
For more information:
Help My House Pilot Program – Summary Report
Environmental and Energy Study Institute – Fact Sheet
Thirteen percent of Americans say they follow science; 65 percent say they follow sports.
Representatives of Major League Baseball, the National Football League, the National Hockey League and NASCAR gathered at the White House yesterday for a half-day conference on “Greening the Games.” The panelists talked about the fact that sports stadiums and arenas across the United States are cultural icons – think Fenway Park, Wrigley Field, the Superdome – and that they offer an extraordinary opportunity for an education in sustainability.
I recently responded to a question on the National Journal blog, "Does climate change cause extreme weather like the heat waves much of the country has been enduring for the past few weeks?"
Learn more about the risks climate change poses to the Gulf Coast, how to fix the National Flood Insurance Program, and EPA's proposed greenhouse gas emissions standard.
Below are the comments C2ES submitted on June 25, 2012, on EPA's proposed greenhouse gas emissions standard for new power plants.
Comments of the Center for Climate and Energy Solutions on
Standards of Performance for Greenhouse Gas Emissions for
New Stationary Sources: Electric Utility Generating Units;
United States Environmental Protection Agency
(77 Fed. Reg. 22392 (April 13, 2012))
Docket ID No. EPA-HQ-OAR-2011-0660; FRL-9654-7
This document constitutes the comments of the Center for Climate and Energy Solutions (C2ES) on the proposed standards of performance for greenhouse gas (GHG) emissions for new electric utility generating units (Proposal), proposed by the U.S. Environmental Protection Agency (EPA) and published in the Federal Register on April 13, 2012. C2ES is an independent nonprofit, nonpartisan organization dedicated to advancing practical and effective policies and actions to address our global climate change and energy challenges. As such, the views expressed here are those of C2ES alone and do not necessarily reflect the views of members of the C2ES Business Environmental Leadership Council (BELC). In addition, the comments made in this document pertain to new sources in the specific industrial sector addressed by the Proposal and may not be appropriate for other industrial sectors or for existing electric utility generating units.
Preference for Market-based Policy
C2ES believes market-based policies—such as emissions averaging among companies, a cap-and-trade system, an emissions tax, or a clean energy standard with tradable credits – would be the most efficient and effective way of reducing GHG emissions and spurring clean energy development and deployment. Properly-designed market-based policies create an appropriate division of labor in addressing climate change, with the law establishing the overarching goal of reducing GHG emissions, and private industry determining how best to achieve that goal. Under market-based policies, the government neither specifies a given company’s emission level nor requires the use of any given technology—both of these questions are determined by the company itself.
Beyond providing an incentive for the use of best available technologies, market-based policies provide a direct financial incentive for inventors and investors to develop and deploy lower-cost, clean energy technologies, and leave the private market to determine technology winners and losers. Market-based policies can be designed to minimize transition costs for companies and their customers in moving from high-emitting technologies to low-emitting technologies; to prevent manufacturers in countries without GHG limits from using this as a competitive advantage over U.S. manufacturers; and to reverse any regressive impacts of increased energy prices. At the federal level, market-based policies have been used to reduce sulfur dioxide emissions at a fraction of the originally estimated cost, while at the state level they have been used successfully in renewable energy programs and cap-and-trade programs.
However, enactment of federal legislation that would establish a comprehensive market-based policy to reduce GHG emissions does not appear imminent. Given the urgency of addressing the rising risks that climate change poses to U.S. economic, environmental and security interests, C2ES believes that in the absence of Congressional action to reduce greenhouse gas emissions, EPA must proceed using its existing authorities under the Clean Air Act.
The Context of the Proposal
The Proposal is consistent with the EPA’s authority to implement the Clean Air Act, as interpreted by the U.S. Supreme Court. On April 2, 2007, in the case of Massachusetts v. EPA, the court found that the harms associated with climate change are serious and well recognized, the EPA has the authority to regulate CO2 and other GHGs under the existing Clean Air Act, and, although enacting regulations may not by itself reverse global warming, that is not a reason for EPA not to act in order to “slow or reduce” global warming.
The Court required that the EPA determine whether GHG emissions from new motor vehicles cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. The EPA released a draft Technical Support Document (TSD) in 2008 that provided technical analysis of the potential risks of GHGs for human health and welfare and contribution of human activities to rising GHG concentrations, and adopted a final endangerment finding in December 2009. The finding explained and documented the determination that (1) the ambient concentration of six key GHGs—CO2, methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—contribute to climate change, which results in a threat to the public health and welfare of current and future generations, and (2) emissions from motor vehicles contribute to the ambient concentration of the GHGs.
The EPA’s endangerment finding did not, by itself, impose any restrictions on any entities. It was, however, a required step in the EPA’s process of regulating GHG emissions. The EPA has already issued several requirements pertaining to GHG emissions—two as a consequence of the endangerment finding, and two in response to specific Congressional mandates regarding the reporting of GHG emissions.
Reporting CO2 emissions from power plants. Under section 821 of the Clean Air Act Amendments of 1990, the EPA requires power plants to monitor their CO2 emissions and report the data to the EPA, which makes the data available to the public. Under this provision, power plants have been reporting their CO2 emissions since the early 1990s, and the data have been made publicly available through the EPA’s website.
GHG Reporting Rule. As part of the Fiscal Year 2008 Consolidated Appropriations Act, signed into law in December 2007, the EPA was ordered to publish a rule requiring public reporting of GHG emissions from large sources. The GHG Reporting Program database was published for the first time in January 2012, and consisted of data reported under the rule.
Vehicle tailpipe standards. The first and most direct result of the Supreme Court’s ruling in Massachusetts V. EPA and the EPA’s subsequent endangerment finding was the EPA’s promulgation of GHG emissions standards for vehicles. In April 2010, the EPA and the U.S. Department of Transportation issued a joint regulation to establish new light-duty vehicle standards for Model Year (MY) 2012 to MY 2016; in August 2011, they issued the final rulemaking for heavy-duty vehicles for MY 2014-2018; and in November 2011, they issued a joint proposal for light-duty vehicle standards for MY 2017 to MY 2025.
New Source Review/Best Available Control Technology. Under the Clean Air Act, major new sources or major modifications to existing sources must employ technologies aimed at limiting air pollutants. Once GHGs were regulated as air pollutants through the vehicle tailpipe standard, the requirement that new or modified sources must use “best available control technology” (BACT) for GHGs also took effect. In November 2010, the EPA released guidance to be used by states in implementing BACT requirements for GHG emissions from major new or modified stationary sources of air pollution. Under the BACT guidance, covered facilities are generally required to use the most energy-efficient technologies available, rather than install particular pollution control technologies. More than a dozen facilities have received permits under the program.
The Proposal is the first GHG standard proposed by the EPA under the New Source Performance Standard provision of the Clean Air Act. Electric power plants account for about one-third of U.S. GHG emissions—nearly twice the contribution of light-duty vehicles.
Comments on the Proposal
C2ES has some concerns with the Proposal, as discussed below. If the concerns are adequately addressed, C2ES supports moving the rule forward.
The EPA should set the emissions standard at a level that can be reliably achieved by currently available technology under reasonably expected operating conditions.
The technology on which the standard in the Proposal is based is natural gas combined cycle (NGCC). It is imperative that the EPA set the GHG emissions standard at a level and in a form that can be reliably achieved by currently available NGCC technology under the full range of reasonably expected operating conditions. A recent study raises questions about the extent to which currently available NGCC units can reliably achieve the standard in the Proposal. In order to maximize the efficiency of the overall interconnected electric system – and often to minimize the overall GHG emissions – it is sometimes necessary to run a particular plant at less than peak efficiency. The standard should reflect this reality.
C2ES agrees that, as proposed, the standard should not cover simple cycle combustion turbines and biomass-fueled boilers.
The standard must be consistent with the advancement of carbon capture and storage technology.
Carbon capture and storage (CCS) is not one of the technologies on which the Proposal’s standard is based. Rather, CCS is a method by which a facility could potentially comply with the NGCC-based standard.
CCS operations have been built at scale in other industrial sectors, but not yet in the electricity sector. The first commercial-scale U.S. power plant with CCS is currently under construction. Power companies are planning several additional CCS projects, some of which will be in conjunction with enhanced oil recovery (EOR). CCS power projects that would supply captured CO2 to EOR are in the planning stages in Texas, Mississippi, California, North Dakota, and Kentucky for the 2014—2020 timeframe. Several more power companies have had plans to build CCS operations that did not go forward primarily because of the cost of CCS and the uncertainty with respect to CO2 emission regulation and legislation.
The Proposal offers an alternative compliance mechanism in which a coal power plant could be operated for 10 years without CCS, followed by 20 years with CCS. While the standard and the alternative compliance mechanism could make it easier for public utility commissions to approve proposals to build coal power plants with CCS, given the current cost and limited demonstration and deployment of CCS technologies, these alone may not be enough to surmount the challenge of financing a plant with CCS. (Please see the discussion of CCS under “Related Matters” below.)
More concerning is the possibility that the standard could inadvertently inhibit the advancement of CCS. For example, one intermediate step in demonstrating the compatibility of CCS with large-scale electricity generation might be to capture and sequester only a fraction of the CO2 from a large coal plant – which might not be allowed under the Proposal. C2ES suggests that the EPA consider mechanisms by which CCS demonstration projects and other operations important to the advancement of CCS could go forward.
Given the unique circumstances of electricity generation today, it is on balance appropriate to set a standard that does not differentiate between fuel types for new power plants. A non-differentiated standard may not, however, be appropriate for other industry sectors or existing sources in this sector.
Perhaps the most novel aspect of the Proposal is that it does not issue separate NSPS for coal and natural gas. Under the Clean Air Act, section 111(b)(2), the EPA “may distinguish among classes, types and sizes within categories of new sources for the purpose of establishing [NSPS] standards.” (Emphasis added.) It has in fact typically been the case that Clean Air Act regulations have established separate air pollution standards for coal- and natural gas-fired power plants. While this differentiation is authorized, however, it is not required by the Clean Air Act. Because the proposed rule would apply to new units only, and because prospective owners have options in selecting the designs of their units, fuel switching (i.e., replacing coal use at existing plants with natural gas) would not be required by the rule.
Moreover, recent developments having nothing to do with GHG regulation, such as the availability of inexpensive natural gas and the regulation of other pollutants, have created conditions under which the GHG emissions intensity of electricity generation is declining. Aside from a small number of facilities far along in the planning process and specifically exempt from the Proposal, no new construction of conventional coal plants is currently foreseen at recent forward market natural gas prices through 2020 (when the Clean Air Act requires that the rule be reevaluated). The Proposal reflects the projections of independent analysts with regard to the future of new coal and natural gas electricity generation. For this reason, the Office of Management and Budget estimates that there will be no cost for industry compliance with the Proposal as compared with the status quo.
That said, it is important to recognize that widely fluctuating natural gas prices are a recent memory, and that, while the majority of independent analysts currently project an abundant and inexpensive supply of natural gas for decades to come, this forecast may prove wrong. Issuing a standard that in effect prohibits the construction of new high-emitting coal plants (i.e., those not using CCS) therefore poses risks – as would issuing a standard that allows the construction of such plants. If the construction of new high-emitting coal plants is effectively prohibited and natural gas prices rise higher than currently foreseen, electricity rates could face an upward pressure. On the other hand, allowing the construction of new high-emitting coal plants could lock in the emissions of those plants for decades to come, exacerbating the challenges the United States faces in reducing its GHG emissions and increasing the risks and costs of dangerous anthropogenic climate change.
On balance, C2ES believes the best choice in implementing the NSPS requirement for new power plants is to issue one standard, regardless of fuel type, but with a mechanism that allows for technological innovation (as discussed above). This should be accompanied by heavy federal investment in low-emitting technologies, including CCS, with the goal of maintaining a diverse set of energy sources in generating the nation’s electricity.
Finally, while the establishment of one emission standard regardless of fuel type may be appropriate with respect to new facilities in the power sector, it may not be appropriate for existing facilities in the power sector or for other sectors for which the EPA may issue regulations.
The United States needs a comprehensive energy strategy that delivers a diverse set of affordable low-emitting sources of electricity.
C2ES believes that as a matter of national policy and economic common sense, it is imperative to enhance energy diversity through programs that advance low-emitting uses of coal and natural gas; nuclear power; renewable energy; and efficiency in generation, transmission and end-use.
In particular, the United States needs an effective strategy for demonstrating CCS and making it inexpensive enough to use on future coal and natural gas power plants. Coal- and natural gas-fired generation will likely be predominant sources of electricity in the United States and most of world’s other major economies for decades to come. It will therefore be essential to advance CCS to the point that its use is economical in the context of electricity generation.
A CCS strategy should include a major research, development and demonstration effort, and subsidies to actively encourage the use of CCS with new and existing natural gas and coal power plants so that the technology can travel down the learning curve. C2ES strongly supports, among other measures, the federal grant programs that have allowed the construction of the previously-mentioned CCS projects. Another option is to establish a trust fund to support demonstration projects at commercial scale for a full range of systems applicable to U.S. power plants. CO2-enhanced oil recovery (CO2-EOR), a practice in which oil producers inject CO2 into wells to draw more oil to the surface, presents an important opportunity to advance CCS while boosting domestic oil production and reducing CO2 emissions. A coalition, co-convened by C2ES, has called for a federal tax credit for capture and pipeline projects to deliver CO2 from industrial and power plants to operating wells. (Note that the recommended tax credit is focused on plant and pipeline operators, rather than EOR operators.)
In addition to investing in CCS, it should be a national priority to invest in and otherwise advance a range of low-emitting energy technologies—for economic, as well as environmental, reasons. The diversity of energy sources used in electricity generation has been a valuable hedge against the unpredictable volatility of the various fuel sources, including natural gas. An electricity sector that increasingly relies on any single fuel would create unintended risks for our economy.
C2ES urges the EPA to move forward with the GHG NSPS for existing power plants, and to do so in a way that builds on existing state programs and allows states to use flexible market-based measures to implement the standards.
As mentioned, C2ES believes market-based policies would be the best way of reducing GHG emissions and spurring clean energy development and deployment. In the absence of a legislated solution, there appears to be an opportunity to utilize market-based policies in the regulation of GHG emissions from existing power plants.
Under section 111(d) of the Clean Air Act, the EPA, in concert with the states, is required to establish GHG emission standards for existing stationary sources—including existing power plants, which account for about one-third of U.S. GHG emissions today. The EPA has, in fact, entered into a settlement agreement under which it will implement section 111(d) for existing power plants. C2ES urges the EPA to move forward in implementing section 111(d) in a manner that can utilize market-based policies as soon as practicable.
Over the next few years, power plant owners will have to make billions of dollars’ worth of decisions about retrofitting, retiring, and replacing a large number of older, carbon-intensive coal plants in light of pending non-climate air, water, and waste regulations. Not knowing what GHG standards these existing facilities will have to meet presents facility owners with enormous uncertainty, greatly complicating and even delaying their decisions, ultimately at the expense of electricity rate payers. Because the Proposal addresses only new sources, this uncertainty pertains even to reconstruction or modification of existing sources. The Proposal mitigates some of the regulatory uncertainty faced by the power sector, but not all.
At the same time, several northeastern states already have an operational regional cap-and-trade program for CO2 from power plants (the Regional Greenhouse Gas Initiative), California is implementing an economy-wide GHG cap-and-trade program, and several states have renewable energy standards, alternative energy standards, or other programs that are effective in reducing the average GHG emission rate across all sources, as well as the overall level of GHG emissions.
C2ES strongly prefers that Congress establish a comprehensive, national market-based GHG reduction policy that would cover both new and existing sources and help to reduce this patchwork quilt of state and regional regulation. In the absence of such legislation, however, C2ES recommends that, in implementing section 111(d) for existing power plants, the EPA issue GHG emission rate-based performance standards in a manner that allows for averaging, banking and trading among sources, giving states the flexibility to adopt various market-based policies that will meet or outperform the standard.
3. Matthew J. Kotchen and Erin T. Mansur, “How Stringent is the EPA’s Proposed Carbon Pollution Standard for New Power Plants?” University of California Center for Energy and Environmental Economics, April 2012.