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Electricity Monthly Update

With Data for January 2023 Release Date: March 24, 2023 Next Release Date: April 25, 2023

Highlights: January 2023

  • Mild weather led to new 12-month wholesale electricity price lows in New England, the Mid-Atlantic, Louisiana, and Texas.

  • Mild temperatures led to a new 12-month low electricity demand in Southern Company on January 1.

  • Net electricity generation in the U.S. decreased by 7.9% compared to January 2022. This significant decrease in electricity generation occurred because the country experienced significantly warmer temperatures this January compared to last year.

Key indicators

Average residential monthly electricity expenditures increased in both nominal and real terms from 2021 to 2022

Data source: U.S. Energy Information Administration, Form EIA-861M, Monthly Electric Power Industry Report, and Form EIA-861, Annual Electric Power Industry Report. The Consumer Price Index deflators are from the Federal Reserve Bank of St. Louis.

Average nominal monthly electricity expenditures for residential customers in the United States increased 13.4%, or approximately $16, from $121 in 2021 to $137 in 2022, based on preliminary data. In inflation-adjusted, or real, dollars, this increase was the largest year-over-year increase since at least 1984, when we began calculating average residential electricity expenditures. A combination of colder weather, which increased residential electricity consumption, and higher power plant fuel costs, which flowed through to drive up retail electricity prices, led to the increase in expenditures. With growth in U.S. inflation, as measured by the consumer price index (CPI), rising to 8% between 2021 and 2022, the inflation-adjusted monthly electricity expenditures for residential customers in the United States increased 5.0%.

Total electricity demand in the United States reached an all-time high of 3.9 terrawatthours (TWh) in 2022, with total residential demand increasing by 3.5% over 2021. Both a colder winter and a hotter summer helped to produce a 2.4% increase in average monthly electricity consumption per residential customer. Average U.S. monthly electricity consumption per residential customer increased from 886 kilowatthours (kWh) in 2021 to 907 kWh in 2022.

Data source: U.S. Energy Information Administration, Form EIA-861M, Monthly Electric Power Industry Report.

Monthly electricity expenditures reflect both the amount of electricity a customer consumes and electricity prices. Although we do not directly collect retail electricity price information, we do collect electricity revenues from which we can derive prices by dividing through by consumption. In 2022, the average U.S. residential electricity price was 15.12 cents/kWh, a 10.7% increase from the 2021 average price of 13.66 cents/kWh. After adjusting for inflation, we estimate that U.S. residential electricity prices went up by 2.5%.

Data source: U.S. Energy Information Administration, Form EIA-861M, Monthly Electric Power Industry Report, and Form EIA-861, Annual Electric Power Industry Report. The Consumer Price Index deflators are from the Federal Reserve Bank of St. Louis.

In general, higher delivered fuel costs to power plants were a primary driver of increased end-use electricity prices in 2022. The cost of fossil fuels delivered to power plants in the electric power sector increased 34% from $3.82 per MMBtu in 2021 to $5.13 per MMBtu in 2022. The increases by fuel were:

• Natural gas: 39%
• Coal: 20%
• Petroleum liquids: 62%

Increased fuel costs were passed along to residential customers and contributed to higher electricity prices.

At the state level, however, regional fuel cost dynamics and differences in weather patterns throughout the country had varying impacts on average residential electricity expenditures. From 2021 to 2022 the average nominal monthly residential electricity expenditure increased in all states except Michigan and Alaska. Percentage changes in average expenditures ranged from a high of +31.8% in Maine to a low of -1.6% in Michigan.

Data source: U.S. Energy Information Administration, Form EIA-861M, Monthly Electric Power Industry Report, and Form EIA-861, Annual Electric Power Industry Report.

The large increase in Maine’s average expenditures was driven by a 32.3% increase in nominal prices. A November 16, 2021 press release from the Maine Public Utilities Commission announced a 2022 increase for Standard Offer electricity supply rates (the rate that applies to customers who do not purchase electricity from a competitive supplier of their choosing and instead receive Standard Offer Supply by default). The release commented that “sharp increases in natural gas prices are resulting in higher electricity supply costs for the upcoming year [2022]. This increase is primarily driven by New England’s wholesale electricity market prices which have increased dramatically.” The average spot price of natural gas at the Algonquin Citygate, the primary proxy for the value of natural gas in New England, rose about 50% in 2022 compared with 2021. Natural gas generally sets the marginal price for wholesale electricity in New England.

The two states with the next highest percentage changes in expenditures were also driven by higher power plant fuel costs. In New Hampshire, high natural gas prices contributed to New Hampshire having the second-highest increase (26.9%) in average nominal residential electricity expenditures. The third-highest increase (24.6%) in nominal residential electricity expenditures was in Hawaii. Hawaii relies extensively on imported petroleum, so the high cost of petroleum during 2022 contributed to the electricity price increase.

Highest and lowest average residential electricity expenditures, 2022
State Average monthly consumption (kWh) Average price (cents/kWh) Average monthly expenditures ($)
Hawaii 515 43.02 221.56
Connecticut 715 24.65 176.25
Alabama 1,191 14.39 171.39
Texas 1,176 13.55 159.35
New Hampshire 624 25.50 158.98
U.S. Avg 907 15.12 137.18
Colorado 717 14.29 102.50
Wyoming 892 11.10 99.06
D.C. 685 14.20 97.24
New Mexico 676 14.11 95.37
Utah 794 10.94 86.88
Source: U.S. Energy Information Administration, Form EIA-861M, Monthly Electric Power Industry Report

In absolute terms, the states with the highest average expenditures were Hawaii, Connecticut, Alabama, Texas, and New Hampshire. Because of its significant use of imported petroleum, Hawaii has the country’s highest average monthly residential electricity expenditure ($221.56) despite having the country’s lowest average residential consumption rate (515 kWh/month).

Two of the top five states with the highest average residential electricity expenditures were in New England: Connecticut and New Hampshire. Connecticut, with the second-highest average expenditures ($176.25 per month), had fairly low average residential consumption levels (715 kWh per month), but it had higher-than-average prices at 24.65 cents/kWh. The higher electricity rates in Connecticut are typical of New England, where prices tend to be higher because of constraints on natural gas pipeline capacity during peak demand periods. The four states with the lowest monthly expenditures in 2022 were Utah ($86.88), New Mexico ($95.37), Wyoming ($99.06), and Colorado ($102.50). The District of Columbia also had a low average monthly expenditure of $97.24. All five of these areas had lower-than-average consumption levels.

End Use: January 2023

Retail rates/prices and consumption

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 kWh by state

Forty-nine states and the District of Columbia saw increased revenue per kilowatt-hour (kWh) compared to last January, as average revenue per kWh increased by 12.7% on a national basis. The largest percent increase was in Nevada, up 46.1%, followed by New Hampshire, up 35.7%, and Connecticut, up 28.6%. Compared to last year, average revenue per kWh figures decreased in only one state, New Mexico. In the contiguous US, New Hampshire, Connecticut, and Massachusetts had the highest average revenues at 25.92, 25.54, and 25.17 cents per kWh, respectively. Minnesota had the median average revenue at 11.26 cents per kWh. Wyoming, North Dakota, and Nebraska had the lowest average revenues at 8.07, 8.21, and 8.42 cents per kWh, respectively.

Retail Service by Customer Sector
  Average Revenues/Sales (¢/kWh)   Retail Sales (thousand MWh)
End-use sector January 2023 Change fromJanuary 2022 January 2023 Change fromJanuary 2022 Year to Date
Residential 15.47 12.8% 132,694 -5.9% 132,694
Commercial 12.79 12.6% 110,077 -2.0% 110,077
Industrial 8.30 13.7% 79,719 -4.3% 79,719
Transportation 12.70 16.4% 568 0.6% 568
Total 12.78 12.7% 323,058 -4.2% 323,058
Source: U.S. Energy Information Administration

Total average revenues per kilowatt-hour (kWh) rose by 12.7% from last January, to 12.78 cents/kWh in January 2023. All four sectors saw increases in average revenues per kWh. The Transportation sector rose the most from last January, up 16.4%, followed by the Industrial sector, up 13.7%, then the Residential sector, up 12.8%, and lastly the Commercial sector, up 12.6%. Total retail sales were down 4.2% from January 2022. Three sectors saw decreases in retail sales. The Residential sector decreased the most from last January, down 5.9%, followed by the Industrial sector, down 4.3%, then the Commercial sector, down 2.0%. Retail sales increased by 0.6% in the Transportation sector.

Retail sales

Thirty-five states and the District of Columbia saw a decrease in retail sales volume in January 2023 compared to January 2022, as retail sales decreased by 4.2% on a national basis. North Carolina had the highest percent year over year decrease, down 18.4%, followed by Maryland, down 15.4%, and Connecticut, down 13.1%. Fifteen states saw an increase in retail sales volume compared to last year. North Dakota had the highest percent year over year increase, up 6.3%, followed by Florida, up 6.2%, and Arizona, up 5.4%.

Eleven states saw an increase in Heating Degree Days (HDDs) from last January. In the contiguous US, California had the highest percent year over year increase, up 31.7%, followed by Arizona, up 31.5%, and Nevada, up 21.5%. Thirty-eight states and the District of Columbia saw a decrease in HDDs. In the contiguous US, the District of Columbia had the highest percent year over year decrease, down 34.7%, followed by Delaware, down 33.3%, and Mississippi, down 32.7%. All states in the eastern half of the country saw a warmer January and thus a decrease in HDDs compared to last year, while most of the western states saw a cooler January and thus an increase in HDDs. When compared to historical normal HDD levels, this January was warmer than normal. Forty-three states and the District of Columbia saw below historical average HDDs and six states saw above historical average HDDs.

Resource Use: January 2023

Supply and fuel consumption

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.

Generation output by region



Net electricity generation in the United States decreased by 7.9% in January 2023 compared to the previous year. This significant decrease in electricity generation occurred because the country, as a whole, experienced significantly warmer temperatures this January compared to last year. Heating Degree Days (HDDs) were down by 20.0% nationwide compared to January 2022. In all regions, this led to a year-over-year decrease in the demand for residential heating and thus a decrease in demand for electricity generation in January 2023 compared to the previous January. In particular, the Northeast (down 11.4%), Central (down 11.1%), Southeast (down 10.4%), and MidAtlantic (down 9.2%) saw the largest percentage decreases in electricity generation after experiencing record or near record warm temperatures in January 2023.

Electricity generation from coal was down in all parts of the country compared to the previous January. The change in natural gas generation was more mixed, with the Northeast, Southeast, Florida, and Texas all seeing a decrease in natural gas generation, while the MidAtlantic, Central, and West all saw year over year increases in electricity from natural gas. Nuclear electricity generation decreased by 0.4% compared to January 2022. Electricity generation from other renewable sources was down in most parts of the country, with Florida (up 14.0%) and Texas (up 20.6%) seeing the only increases in renewables generation compared to January 2022.

Fossil fuel consumption by region





The chart above compares coal consumption in January 2022 and January 2023 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 saw their share of natural gas increase at the expense of coal.

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.

Fossil fuel prices



To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average spot 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 decreased significantly from the previous month, going from $5.74/MMBtu in December 2022 to $3.37/MMBtu in January 2023. The natural gas price for New York City (Transco Zone 6 NY) also saw a significant decrease from the previous month, going from $12.03/MMBtu in December 2022 to $3.51/MMBtu in January 2023. The average spot price of Central Appalachian coal decreased from the previous month, going from $8.51/MMBtu in December 2022 to $6.72/MMBtu in January 2023.

The New York Harbor residual oil price saw an increase in price from the previous month, going from $11.60/MMBtu in December 2022 to $12.38/MMBtu in January 2023. As is the case in most months, oil was priced out of electricity markets for baseload operations in January 2023.

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 Henry Hub natural gas price ($27.01/MWh) saw a significant decrease from the previous month ($45.95/MWh) and was well below the Central Appalachian coal price ($72.55/MWh) in January 2023. The price of natural gas at New York City ($28.13/MWh) decreased significantly from the previous month ($96.33/MWh) and was now below the price of Central Appalachian coal ($72.55/MWh) during January 2023.

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.

Regional Wholesale Markets: January 2023

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.

Wholesale prices



Wholesale daily electricity and natural gas prices were bifurcated in January, with prices high across the western US and much lower east of the Rocky Mountains. Wholesale electricity prices peaked between $175/MWh and $226/MWh at the four western price points (El Paso San Juan, SoCal Border, PG&E Citygate, and Sumas), while high prices east of the Rockies remained below $95/MWh during the month. Prices in the Midwest and eastern US fell enough to set new 12-month lows in New England (ISONE) at $36/MWh, the Mid-Atlantic (PJM) at $32/MWh, Louisiana (into Entergy) at $24/MWh, and in Texas (ERCOT) at $15/MWh. Wholesale natural gas price highs for the month ranged between $20/MMBtu and $27/MMBtu at the four western price hubs (El Paso San Juan, SoCal Border, PG&E Citygate and Sumas). Prices east of the Rockies peaked at $12/MMBtu in New England (Algonquin) and between $3.43-$4.13/MMBtu at all other price hubs. A new 12-month low price of $2.72/MMBtu was recorded on January 27 at the Henry Hub in Louisiana.

Electricity system daily peak demand


Electricity demand remained elevated in the Bonneville Power Administration (BPA) system during January after setting a new 12-month high in December. BPA demand of 10,693 MW on January 30 was just 3% lower than the annual high set last month. Demand levels were seasonally low in the Northeast as New Jersey and all New England states recorded their warmest January on record this year. Demand in Southern Company set a new 12-month low on January 1 of 21,592 MW as temperatures in the Southeast remained very mild during the month.

Electric Power Sector Coal Stocks: January 2023


Total U.S. coal stockpiles had a month-over-month increase of 4.6%, reaching 94 million tons in January 2023. This increase in total U.S. coal stockpiles deviates from the normal seasonal pattern whereby coal power plants usually consume their stockpiles in the colder months to generate electricity and meet increased electricity demand. Due to the unseasonably warm temperatures observed throughout the country in January 2023, there was a reduced demand for electricity and thus, a decreased need to draw down coal stockpiles.

Days of burn



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 120 days of forward-looking days of burn in December 2022 to 133 days of burn in January 2023. For subbituminous units largely located in the western United States, the average number of days of burn also increased, going from 113 days of burn in December 2022 to 125 days of burn in January 2023.

Coal stocks and average number of days of burn for non-lignite coal by region (electric power sector)

    January 2023 January 2022   December 2022  
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
Northeast Bituminous 2,972 365 2,169 349 37.1% 2,521 365 17.9%
  Subbituminous . . . . . . . .
South Bituminous 17,040 133 11,824 100 44.1% 15,741 124 8.3%
  Subbituminous 4,232 86 3,559 67 18.9% 3,663 59 15.5%
Midwest Bituminous 9,021 108 8,657 104 4.2% 8,608 89 4.8%
  Subbituminous 22,048 133 20,006 137 10.2% 22,997 141 -4.1%
West Bituminous 2,127 151 2,150 138 -1.1% 2,131 153 -0.2%
  Subbituminous 19,914 125 19,178 120 3.8% 18,658 107 6.7%
U.S. Total Bituminous 31,160 133 24,800 111 25.6% 29,000 120 7.4%
  Subbituminous 46,194 125 42,743 121 8.1% 45,317 113 1.9%

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.

Methodology and Documentation

General

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.

Key Indicators

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.

  • Total Net Generation:  Reflects the total electric net generation for all reporting sectors as collected via the Form EIA-923.
  • Residential Retail Price:  Reflects the average retail price as collected via the Form EIA-826.
  • Retail Sales:  Reflects the reported volume of electricity delivered as collected via the Form EIA-826.
  • Degree-Days:  Reflects the total population-weighted United States degree-days as reported by the National Oceanic and Atmospheric Administration.
  • Natural Gas Henry Hub:  Reflects the average price of natural gas at Henry Hub for the month.  The data are provided by Bloomberg. 
  • Coal Stocks:  Reflects the total coal stocks for the Electric Power Sector as collected via the Form EIA-923.
  • Coal Consumption:  Reflects the total coal consumption as collected via the Form EIA-923.
  • Natural Gas Consumption:  Reflects the total natural gas consumption as collected via the Form EIA-923.
  • Nuclear Outages:  Reflects the average daily outage amount for the month as reported by the Nuclear Regulatory Commission's Power Reactor Status Report and the latest net summer capacity data collected on the EIA-860 Annual Generator Report.

Sector Definitions

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

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).

Per Capita Retail Sales

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.

Composition of Fuel Categories

Net generation statistics are grouped according to regions (see Electricity Monthly Update Explained Section) by generator type and fuel type. Generator type categories include:

  • Fossil Steam:  Steam turbines powered by the combustion of fossil fuels
  • Combined Cycle:  Combined cycle generation powered by natural gas, petroluem, landfill gas, or other miscellaneous energy sources
  • Other Fossil:  Simple cycle gas turbines, internal combustion turbines, and other fossil-powered technology
  • Nuclear Steam:  Steam turbines at operating nuclear power plants
  • Hydroelectric:  Conventional hydroelectric turbines
  • Wind:  Wind turbines
  • Other renewables: All other generation from renewable sources such as geothermal, solar, or biomass
  • Other:  Any other generation technology, including hydroelectric pumped storage

Generation statistics are also displayed by fuel type. These include:

  • Coal:  all generation associated with the consumption of coal
  • Natural Gas:  all generation associated with the consumption of natural gas
  • Nuclear:  all generation associated with nuclear power plants
  • Hydroelectric:  all generation associated with conventional hydroelectric turbines
  • Other Renewable: all generation associated with wind, solar, biomass, and geothermal energy sources
  • Other Fossil: all generation associated with petroleum products and fossil-dervied fuels
  • Other:  all other energy sources including waste heat, hydroelectric pumped storage, other reported sources

Relative Fossil Fuel Prices

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

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:

  • Northeast — New England, Middle Atlantic
  • South — South Atlantic, East South Central
  • Midwest — West North Central, East North Central
  • West — Mountain, West South Central, Pacific Contiguous

Coal Stocks vs. Days of Burn Stocks

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.