In 2015, coal-fired electricity generation, at 1.352 million gigawatthours (GWh), was the largest source of electricity generation in the United States. However, in 2020, coal was the third-largest source of electricity generation (0.774 million GWh), falling lower than both natural gas (1.617 million GWh) and nuclear generation (0.790 million GWh). Even with this decrease, coal-fired generation is still capable of supplying a significant share of U.S. generation. EIA’s Hourly Grid Monitor shows increased coal-fired generation in the first weeks of 2021 as natural gas prices have returned to higher levels. The longer-term decline in coal-fired generation, however, is a result of the build-up of natural gas generators and wind facilities that both began in the late 1990s. Two different trends in the electric power industry—changes in capacity and changes in generation—have affected coal-fired generation trends.
Natural gas-fired capacity has been steadily increasing since the early 1990s. Between 1998 and 2003, natural gas-fired capacity nearly doubled at an average annual growth rate of 15% per year. Because of this rapid increase, natural gas-fired generating capacity exceeded coal-fired generating capacity for the first time in 2003. Natural gas-fired capacity has continued to grow every year since then, leading to a widening gap between coal-fired and natural gas-fired capacity. As natural gas prices fell in 2009, coal-fired generation dropped 12% in a single year. Although coal-fired generation remained the primary source of generation in the United States until 2015, the downward trend in coal-fired generation soon led to the closing of many coal-fired generators starting in 2012 and accelerating by 2015. By the end of 2020, natural gas-fired capacity (482.6 gigawatts [GW]) exceeded coal-fired capacity (218.4 GW) by approximately two-to-one.
At about the same time that natural gas-fired capacity was being built up in the late 1990s and early 2000s, wind capacity was also growing—but at a faster rate. From 1998 to 2009, wind capacity grew from 1.7 GW to 34.3 GW at an average annual rate of 31% per year. Initially, wind capacity represented a small fraction of existing U.S. generating capacity, but by 2012 it represented more than 5% of U.S. generating capacity. By 2019, wind capacity surpassed nuclear capacity and became the third-largest source of generating capacity in the United States. At the end of 2020, wind capacity (117.7 GW) represented more than 10% of U.S. generating capacity. The trend in wind generation followed closely behind this trend in capacity. By 2016, wind represented more than 5% of total U.S. electricity generation, and in 2019 it surpassed hydroelectric generation to become the fourth-largest source of U.S. net generation.
During the past decade, the decline in coal-fired generation has largely been offset by increases in wind and natural gas-fired generation, but solar generation has been another major contributor. Just as wind capacity grew quickly in the late 1990s, solar generating capacity grew quickly beginning in 2007 and has grown by more than 15% every year since 2009. In both 2012 and 2013, solar capacity more than doubled from the previous year. By the end of 2020, solar capacity (47.8 GW) represented more than 4% of U.S. generating capacity, and solar generation (90.9 thousand GWh) represented more than 2% of U.S. electricity generation.
In this section, we look at what electricity costs and how much is purchased. Charges for retail electric service are based primarily on rates approved by state regulators. However, a number of states have allowed retail marketers to compete to serve customers and these competitive retail suppliers offer electricity at a market-based price.
EIA does not directly collect retail electricity rates or prices. However, using data collected on retail sales revenues and volumes, we calculate average retail revenues per kWh as a proxy for retail rates and prices. Retail sales volumes are presented as a proxy for end-use electricity consumption.
Average revenue per kilowatthour figures decreased in eighteen states and the District of Columbia in December compared to last year. The largest decline was found in South Carolina, down by 10.5%. Thirty-two states increased revenue per kilowatt-hour compared to last year, led by Georgia, up16.9%. Ohio was notable in that the state’s average revenue per kilowatthour remained almost unchanged compared to the previous December, only seeing a 0.1% decrease from last December.
|Average Revenues/Sales (¢/kWh)||Retail Sales (thousand MWh)|
|End-use sector||December 2020||Change fromDecember 2019||December 2020||Change fromDecember 2019||Year to Date|
|Source: U.S. Energy Information Administration|
Total average revenues per kilowatt-hour (kWh) rose by 2.2% from last December, to 10.44 cents/kWh. The Transportation sector rose the most from last December, up by 3.7%. The Commercial, Residential, and Industrial sectors all also rose, up by 1.6%, 0.9%, and 0.3% respectively. Total retail sales were up 0.3% from December 2019. The Residential sector was the main driving force, up 7.0% from a year ago. The other three sectors saw a drop in retail sales from a year ago. The Industrial sector dropped the most, down by 4.8%. The Commercial and Transportation sectors followed, down by 3.3% and 2.6%, respectively.
State retail sales volumes were down in twenty-six states and the District of Columbia in December compared to last year. Wyoming had the largest year-over-year decline, down more than 8%. Montana and Hawaii followed, dropping by 7.4% and 6.8% respectively. Twenty-four states saw an increase in retail sales volume in December, led by Georgia, up 7.3%. Virginia and Alabama followed, up 6.6% and 5.9%, respectively. North Dakota had the highest sales per capita.
Heating Degree Days (HDD) were down in fifteen states this December compared to last December. The greatest percentage drop in HDDs occurred in North Dakota, which was down almost 15% between years. South Dakota and Maine followed, both down 8.0% compared to 2020. Thirty-three states and the District of Columbia had an increase in HDDs from last December. Florida had the largest percent increase in HDDs, up 162% from December 2019. Alabama, Georgia, and South Carolina followed, all with increases of over 30% in HDDs, indicating a colder December in the Southeast relative to December 2019. The Dakotas and New England states saw less HDDs than normal, while the Southeast and Southwest saw more HDDs than normal.
In this section, we look at the resources used to produce electricity. Generating units are chosen to run primarily on their operating costs, of which fuel costs account for the lion's share. Therefore, we present below, electricity generation output by fuel type and generator type. Since the generator/fuel mix of utilities varies significantly by region, we also present generation output by region.
Net electricity generation in the United States increased 1.9% in December 2020 compared to the previous year. This increase in electricity generation occurred, in part, because the country, as a whole, experienced a colder winter in December 2020 relative to December 2019. HDDs were up by 5.2% in December relative to December 2019. This led to an increase in the demand for residential heating and thus, a subsequent increase in the demand for electricity. At the regional-level, the MidAtlantic, Southeast, Central, and Florida all saw a year-over-year increase in electricity generation, while the Northeast, West, and Texas all saw a decrease in electricity generation from the previous year.
Electricity generation from coal increased from the previous December in all parts of the country, except the West, while electricity generation from natural gas decreased in all parts of the country, except for in the Southeast. The national increase in coal generation (8.4%) versus the decrease in natural gas generation (-4.7%) was mainly driven by increases in the price of natural gas in the face of steady prices for coal. The Southeast saw a year-over-year increase in electricity generation from natural gas (up 5.3%) and total electricity generation (up 4%) mainly due to the cooler temperatures experienced this December compared to the previous year. This led to an increase in the need for residential heating in this part of the country where electricity is used as one of the main sources of residential heating.
Nuclear generation, as a whole, was down by 4.4% compared to a year ago, as many nuclear plants were still undergoing scheduled maintenance during December 2020. All regions of the country, except for the Northeast and MidAtlantic, saw an increase in other renewables generation compared to the previous December.
The chart above compares coal consumption in December 2019 and December 2020 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption were similar to their respective changes in coal and natural gas generation.
The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. All regions of the country, except for the West, saw their share of coal increase at the expense of natural gas.
The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were similar to the changes seen in total coal and natural gas net generation in each region.
To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $/MMBtu basis as shown in the chart above. The average price of natural gas at Henry Hub remained relatively unchanged from the previous month, only dropping by $0.01/MMBtu from $2.64/MMBtu in November 2020 to $2.63/MMBtu in December 2020. However, the natural gas price for New York City (Transco Zone 6 NY) saw a significant month-over-month increase, going from $1.74/MMBtu in November 2020 to $2.75/MMBtu in December 2020. The average price of Central Appalachian coal increased from the previous month, going from $2.25/MMBtu in November 2020 to $2.32/MMBtu in December 2020.
The New York Harbor residual oil price saw an increase in price from the previous month, going from $9.11/MMBtu in November 2020 to $10.23/MMBtu in December 2020. As is the case most months, oil was largely priced out of most electricity markets for baseload operations.
A fuel price comparison based on equivalent energy content ($/MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. The price of natural gas at Henry Hub ($21.09/MWh) was below the price of Central Appalachian coal ($25.10/MWh) on a $/MWh basis, with the spread between the two increasing slightly compared to last month. The price of natural gas at New York City ($22.00/MWh) was below the price of Central Appalachian coal ($25.10/MWh) during December 2020, with the spread between the two prices decreasing significantly, mainly due to the significant increase in the price of natural gas at New York City.
The conversion shown in this chart is done for illustrative purposes only. The competition between coal and natural gas to produce electricity is more complex. It involves delivered prices and emission costs, the terms of fuel supply contracts, and the workings of fuel markets.
The United States has many regional wholesale electricity markets. Below we look at monthly and annual ranges of on-peak, daily wholesale prices at selected pricing locations and daily peak demand for selected electricity systems in the Nation. The range of daily prices and demand data is shown for the report month and for the year ending with the report month.
Prices and demand are shown for six Regional Transmission Operator (RTO) markets: ISO New England (ISO-NE), New York ISO (NYISO), PJM Interconnection (PJM), Midwest ISO (MISO), Electric Reliability Council of Texas (ERCOT), and two locations in the California ISO (CAISO). Also shown are wholesale prices at trading hubs in Louisiana (into Entergy), Southwest (Palo Verde) and Northwest (Mid-Columbia). In addition to the RTO systems, peak demand is also shown for the Southern Company, Progress Florida, and the Bonneville Power Authority (BPA). Refer to the map tabs for the locations of the electricity and natural gas pricing hubs and the electric systems for which peak demand ranges are shown.
In the second tab immediately below, we show monthly and annual ranges of on-peak, daily wholesale natural gas prices at selected pricing locations in the United States. The range of daily natural gas prices is shown for the same month and year as the electricity price range chart. Wholesale electricity prices are closely tied to wholesale natural gas prices in all but the center of the country. Therefore, one can often explain current wholesale electricity prices by looking at what is happening with natural gas prices.
The arrival of a cold front in mid-December across the Midcontinent and Eastern United States caused a short-term spike in wholesale electricity and natural gas prices in these regions. Wholesale natural gas prices set new 12-month highs on December 17 of $5.38/MMBtu in New York City (Transco Z6 NY). The next day on December 18, New England (Algonquin) set a new 12-month high of $11.50/MMBtu and the Mid-Atlantic (Tetco M-3) also set a high at $5.57/MMBtu. Meanwhile, prices at the Henry Hub in Louisiana ranged from $2.36-$2.89/MMBtu during the month. Wholesale electricity prices set new 12-month highs this month on December 15 in Louisiana (into Entergy) at $39.25/MWh and on December 18 at $104/MWh in New England (ISONE) and at $70/MWh in New York City (NYISO). High prices remained below $51/MWh at all other selected trading hubs during the month.
Electricity system daily peak demands were higher in December than November on all selected systems, though demand remained on the lower-end to middle of each systems’ annual range. Compared to all-time peak demand levels in each region, demand in December ranged from only 59% of all-time peak in California (CAISO) to 80% of all-time peak in Southern Company. These moderate demand levels are a reflection of slightly above-average temperatures across the southern United States to much above-average and nearly record warmth in the northern United States. This had a dampening effect on energy demand as less space-heating load was required.
Total U.S. coal stockpiles had a month-over-month decrease of 2.5%, reaching 133 million tons in December 2020. This November to December decrease in total U.S. coal stockpiles follows the normal seasonal pattern, as coal stockpiles decrease in the colder months as coal-fired generators meet the winter demand for electricity.
The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn increased from the previous month, going from 140 days of forward-looking days of burn in November 2020 to 145 days of burn in December 2020. For subbituminous units largely located in the western United States, the average number of days of burn also increased, going from 114 days of burn in November 2020 to 125 days of burn in December 2020.
|December 2020||December 2019||November 2020|
|Zone||Coal||Stocks (1000 tons)||Days of Burn||Stocks (1000 tons)||Days of Burn||% Change of Stocks||Stocks (1000 tons)||Days of Burn||% Change of Stocks|
Source: U.S. Energy Information Administration
NOTE: Stockpile levels shown above reflect a sample of electric power sector plants, which were used to create the days of burn statistics. These levels will not equal total electric power sector stockpile levels.
The Electricity Monthly Update is prepared by the Electric Power Operations Team, Office of Electricity, Renewables and Uranium Statistics, U.S. Energy Information Administration (EIA), U.S. Department of Energy. Data published in the Electricity Monthly Update are compiled from the following sources: U.S. Energy Information Administration, Form EIA-826,"Monthly Electric Utility Sales and Revenues with State Distributions Report," U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," fuel spot prices from Bloomberg Energy, electric power prices from SNL Energy, electric system demand data from Ventyx Energy Velocity Suite, and weather data and imagery from the National Oceanic and Atmospheric Administration.
The survey data are collected monthly using multiple-attribute cutoff sampling of power plants and electric retailers for the purpose of estimation for various data elements (generation, stocks, revenue, etc.) for various categories, such as geographic regions. (The data elements and categories are "attributes.") The nominal sample sizes are: for the Form EIA-826, approximately 450 electric utilities and other energy service providers; for the Form EIA-923, approximately 1900 plants. Regression-based (i.e., "prediction") methodologies are used to estimate totals from the sample. Essentially complete samples are collected for the Electric Power Monthly (EPM), which includes State-level values. The Electricity Monthly Update is based on an incomplete sample and includes only regional estimates and ranges for state values where applicable. Using "prediction," it is generally possible to make estimates based on the incomplete EPM sample, and still estimate variances.
For complete documentation on EIA monthly electric data collection and estimation, see the Technical Notes PDF to the Electric Power Monthly. Values displayed in the Electric Monthly Update may differ from values published in the Electric Power Monthly due to the additional data collection and data revisions that may occur between the releases of these two publications.
Accessing the data: The data included in most graphics can be downloaded via the "Download the data" icon above the navigation pane.Some missing data are proprietary and non-public.
For a guide that describes electricity data that EIA collects and how the data are made available to the public, see the Guide to EIA Electric Power Data.
The Key Indicators in the table located in the "Highlights" section, are defined below. The current month column includes data for the current month at a national level. The units vary by statistic, but are included in the table. The "% Change from 2010" value is the current month divided by the corresponding month last year (e.g. July 2011 divided by July 2010). This is true for Total Generation, Residential Retail Price, Retail Sales, Degree-Days, Coal Stocks, Coal and Natural Gas Consumption. The Henry Hub current month value is the average weekday price for the current month. The Henry Hub "% Change from 2010" value is the average weekday price of the same month from 2010 divided by the average weekday price of the current month.
The Electric Power Sector comprises electricity-only and combined heat and power (CHP) plants within the North American Industrial Classification System 22 category whose primary business is to sell electricity, or electricity and heat, to the public (i.e., electric utility plants and Independent Power Producers (IPPs), including IPP plants that operate as CHPs). The All Sectors totals include the Electric Power Sector and the Commercial and Industrial Sectors (Commercial and Industrial power producers are primarily CHP plants).
Degree-days are relative measurements of outdoor air temperature used as an index for heating and cooling energy requirements. Heating degree-days are the number of degrees that the daily average temperature falls below 65° F. Cooling degree-days are the number of degrees that the daily average temperature rises above 65° F. The daily average temperature is the mean of the maximum and minimum temperatures in a 24-hour period. For example, a weather station recording an average daily temperature of 40° F would report 25 heating degree-days for that day (and 0 cooling degree-days). If a weather station recorded an average daily temperature of 78° F, cooling degree-days for that station would be 13 (and 0 heating degree days).
The per capita retail sales statistics use 2011 population estimates from the U.S. Census Bureau and monthly data collected by the Energy Information Administration. The volume of electricity delivered to end users for all sectors in kilowatthours is divided by the 2011 population estimate for each state.
Net generation statistics are grouped according to regions (see Electricity Monthly Update Explained Section) by generator type and fuel type. Generator type categories include:
Generation statistics are also displayed by fuel type. These include:
Relative fossil fuel prices are daily averages of fossil fuel prices by month, displayed in dollars per million British thermal units as well as adjusted for operating efficiency at electric power plants to convert to dollars per megawatthour. Average national heat rates for typical operating units for 2010 were used to convert relative fossil fuel prices.
Average Days of Burn is defined as the average number of days remaining until coal stocks reach zero if no further deliveries of coal are made. These data have been calculated using only the population of coal plants present in the monthly Form EIA-923. This includes 1) coal plants that have generators with a primary fuel of bituminous coal (including anthracite) or subbituminous, and 2) are in the Electric Power Sector (as defined in the above "Sector definitions"). Excluded are plants with a primary fuel of lignite or waste coal, mine mouth plants, and out-of-service plants. Coal storage terminals and the related plants that they serve are aggregated into one entity for the calculation of Average Days of Burn, as are plants that share stockpiles.
Average Days of Burn is computed as follows: End of month stocks for the current (data) month, divided by the average burn per day. Average Burn per Day is the average of the three previous years' consumption as reported on the Form EIA-923.
These data are displayed by coal rank and by zone. Each zone has been formed by combining the following Census Divisions:
The coal stocks data presented at the top of the Fossil Fuel Stocks section (“Coal Stocks”) will differ from the coal stocks presented in the Days of Burn section (“DOB Stocks”) at the bottom of the Fossil Fuel Stocks section. This occurs because Coal Stocks include the entire population of coal plants that report on both the annual and monthly Form EIA-923. The DOB Stocks only include coal plants that report on the monthly Form EIA-923 and have a primary fuel of bituminous (including anthracite) or subbituminous as reported on the Form EIA-860.