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Electricity Monthly Update

With Data for August 2015  |  Release Date: Oct. 27, 2015  |  Next Release Date: Nov. 30, 2015

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Highlights: August 2015

  • All-time peak demand records were set in Southern Company, which reached 48,142 MW on August 17, and in Texas (ERCOT), which reached 69,783 on August 10.
  • For the second consecutive month, electricity generation from coal decreased in all regions of the country, while natural gas generation increased in all regions, except for Florida.
  • Hawaii had the largest decline in average revenue per kilowatthour of any state for the eighth month in a row, and has had year-over-year declines of greater than 20% for the last six months.

Key Indicators

  August 2015 % Change from August 2014
Total Net Generation
(Thousand MWh)
392,298 2.1%
Residential Retail Price
12.93 -0.7%
Retail Sales
(Thousand MWh)
358,676 3.1%
Cooling Degree-Days 312 6.8%
Natural Gas Price, Henry Hub
2.85 -28.9%
Natural Gas Consumption
1,057,595 13.8%
Coal Consumption
(Thousand Tons)
74,145 -8.6%
Coal Stocks
(Thousand Tons)
158,118 31.0%
Nuclear Generation
(Thousand MWh)
72,415 1.8%

Axis-tracking technologies improve photovoltaic system capacity factors

Source: Form EIA-860, Annual Electric Generator Report

Note: "Other" includes dual-axis technologies and facilities that include some combination of fixed and tracking technologies. These facilities averaged less than 5% of total utility-scale photovoltaic installations throughout 2014.

The performance of utility-scale solar installations, those with a nameplate capacity of one megawatt (MW) or greater, is a result of many geographic and technological factors. One of these technological factors is tracking systems that allow the photovoltaic systems to follow the sun and maximize direct sunlight exposure for sunlight-to-electricity conversion.

Fixed-axis panels have fixed mounts at a specific angle that do not change. These installations are simpler but must rely more on the diffuse light available throughout the day rather than the direct sunlight that contains a vast majority of the sun's energy. Single-axis trackers enable the photovoltaic receptors to follow the sun throughout the day, improving direct sunlight exposure and electricity generation potential. Double-axis trackers can move in two directions, accounting for both the seasonal and daily movements of the sun across the sky.

EIA collects information on generator-specific tracking technologies on the survey Form EIA-860. By linking electricity generation data to Form EIA-860 nameplate capacity data, capacity factors can be measured and compared. Capacity factor is the actual amount of electricity generated relative to absolute maximum potential output, expressed as a percentage. For example, a 100 MW generator would need to produce 2,400 MWh to have a 100% capacity factor on a particular day (100 MW X 24 hours) and would have a 50% capacity factor if it generated 1,200 MWh on that day.

In aggregate, the capacity factor for all solar photovoltaic generators in 2014 was 27.8%. What the aggregate capacity factor masks is the considerable variation in unit-level capacity factors as a result of geography and tracking technologies. Fixed-axis installations had an average capacity factor of 25% for all of 2014, with a peak capacity factor of 33% in June. Single-axis installations that can track the sun throughout the course of a day on average had a higher capacity factor than fixed-axis installations in every month of 2014. Single-axis capacity factors averaged 29% across the year and peaked at 40% in June.

The differences in capacity factors between fixed- and single-axis installations was most apparent from late spring to early fall when axis-tracking technology could take advantage of the longer periods of more intense sunlight. During January and February and then October through December, the capacity factor for single-axis installations averaged 22%, just slightly higher than the average capacity factor of 20% for single-axis installations. But from April through September, the capacity factor for single-axis installations averaged 36%, well above the 30% for fixed-axis installations.

Every installation has a unique set of characteristics. Solar technology developers and operators must weigh the increased capacity factor against possible increases in installation and operating and maintenance costs. However, single-axis installations are generally larger than fixed-axis installations because the increased complexity of those systems may require higher levels of electricity generation to justify the additional expense.

A practical example of the difference between a fixed-tilt installation and a single-axis installation is that a 10 MW single-axis installation would on average produce 2,880 MWh in June at a 40% capacity factor, 504 MWh more than a fixed-tilt installation at a 33% capacity factor.

Principal Contributor:

Tim Shear


End Use: August 2015

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

Average revenue per kilowatthour figures were higher in 28 states and lower in 22 states and the District of Columbia during the month of August. Nearly all states were +/- 5% difference from last August except West Virginia, up 12%, Maine and Arkansas, both up nearly 6%, and Hawaii, which was down 21%. Hawaii had the largest decline of any state for the eighth month in a row and has had year-over-year declines of greater than 20% for the last six months. Hawaii's bulk power system is largely petroleum-fueled and has benefitted greatly from the large fall in world oil prices that began in the latter half of 2014. We should continue to see these precipitous year-over-year declines for the next several months as a significant change in a wholesale commodity price is not always immediately reflected in a retail consumers' bill. It can take several months, or longer, for new contracts and deliveries that reflect the current price of the commodity. In this case, Hawaii's average revenue per kilowatthour fell steadily from 34.02 cents in September 2014 to 27.03 cents in February 2015 and has remained close to that level ever since.

Total average revenues per kilowatthour were 10.86 cents in August, down 0.5% from last year. For the third month in a row, all sectors declined relative to one year ago. The Commercial and Transportation sectors were both down 1.5%, the Industrial sector was down 0.8%, and the Residential sector declined 0.7%.

Total retail sales volumes were up 3.1% to 358,676 GWh in August compared to last year, though this is down slightly from July's 359,549 GWh total retail sales volumes. The largest increase occurred in the largest sector by volume, with the Residential sector up 6.4% to 144,086 GWh. The Commercial sector was up 1.4% to 128,229 GWh and the Industrial sector was up 0.2%. The Transportation sector was the only sector down compared to last year, falling 2.7% to 623 GWh.

Retail sales

In the month of August, retail sales volumes tend to correlate closely with weather patterns during the peak of summer. Weather ranges from warm to very hot across the country, unlike shoulder periods where temperature differences can mean different things in different parts of the country. This August, temperatures across much of the country trended warmer than last year, and lo and behold, most states (39 and the District of Columbia) had increased levels of retail sales volumes. The largest temperature increases were found in the Northeast, Mid-Atlantic, South, and Rocky Mountain regions and states in those areas mirrored that pattern with higher retail sales volumes. Rhode Island had the largest gain of any state, up 32%, followed by North Dakota, up 12%, Nevada, up 11%, and New Jersey, up 10%. Temperatures trended cooler in the Great Lakes/Midwest, Northwest, and Florida, and in these areas, states tended to have lower retail sales volumes than last August. Of the few states (11) with lower levels of retail sales volumes compared to last year, Minnesota had the largest decline, down 5%, followed by Oklahoma, Washington, and California, which were all down between 2-3%.

Cooling Degree Day (CDD) trends were fairly consistent during the month of August. Most states had higher to much higher levels of CDDs compared to last year, with the largest differences found in the Northeast, Mid-Atlantic, Rocky Mountain, and Southwest regions. The hottest weather relative to last August occurred in the Northeast, where the nine states with the largest year-over-year increases were found. Every state north and east of Pennsylvania and New Jersey had CDD increases greater than 46%, with Maine, New Hampshire, Massachusetts, and Vermont CDD having levels more than double those from last August. CDD levels were lower in the Great Lakes/Midcontinent area down into Alabama and Florida and also in the Northwest. The largest declines could be found in Missouri, Kansas, and Indiana, all down more than 25%.


Resource Use: August 2015

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

map showing electricity regions

In August 2015, net generation in the United States increased 2.1% compared to the previous August. At the regional level, all regions of the country except for the Central region and Florida saw an increase in electricity generation compared to August 2014. Florida saw electricity generation decrease compared to last August because in August 2014, Florida experienced significantly high temperatures during the month whereas in August 2015, Florida only experienced slightly above average temperatures. The Central region also saw a decrease in electricity generation, but this was a result of cooler than normal temperatures experienced during this August, which decreased the demand for residential cooling in the region and thus, decreased the need for electricity generation compared to the previous year.

For the second consecutive month, electricity generation from coal decreased in all regions of the country. Subsequently, all regions of the country saw an increase in electricity generation from natural gas, except for Florida, which saw a very slight decrease in natural gas generation compared to August 2014. Total electricity generation from nuclear was up, increasing 1.8% compared to the previous August. The Western region continues to see a decline in conventional hydroelectric generation compared to the previous year, with electricity generation from hydroelectric generators decreasing 8% from last August 2014.

Fossil fuel consumption by region

map showing electricity regions

The chart above compares coal consumption in August 2014 and August 2015 by region and shows that, like electricity generation from coal, coal consumption decreased in all regions of the country for the second consecutive month.

The second tab compares natural gas consumption by region and shows that changes in natural gas consumption from the previous August were very similar to the changes in electricity generation from natural gas over the same period.

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. In August 2015, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption compared to the previous year.

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 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 slightly from the previous month, going from $2.91/MMBtu in July 2015 to $2.85/MMBtu in August 2015. However, the natural gas price for New York City (Transco Zone 6 NY) saw an increase from the previous month, going from $2.06/MMBtu in July 2015 to $2.48/MMBtu in August 2015.

For the second consecutive month, the New York Harbor residual oil price saw a significant decrease from the previous month, going from $8.69/MMBtu in July 2015 to $7.34/MMBtu in August 2015. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.

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. For the eighth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. However, the spread between the two prices narrowed considerably due to the month-to-month decrease in the price of Central Appalachian coal. The spread between the New York City gas price and the price of Central Appalachian coal also decreased compared to the previous month, a result of the increase in the natural gas price of New York City coupled with the decrease in the Central Appalachian coal price.

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: August 2015

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, Tucson Electric, 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

Selected wholesale electricity pricing locations

Daily on-peak wholesale electricity prices maxed out in August between $40/MWh and $65/MWh across all hubs with the notable exception of Texas (ERCOT). Prices in Texas reached $164/MWh on Friday, August 7 and remained high at $122/MWh on Monday, August 10 and $159/MWh on Tuesday, August 11. This was a period of extremely high electricity demand in Texas (ERCOT), which is covered in more detail in the Daily Peak Demand section below, and ERCOT's system-wide offer cap increased to $9,000 MWh on June 1, 2015. The high system-wide offer cap is designed to encourage any and all forms of generation during critical peak demand periods, though it can also lead to periods of extremely high electricity prices.

Even with healthy summer demand levels across the country, daily electricity prices were fairly muted at the other hubs due to continuing low natural gas prices. Prices remained below $3/MMBtu at most pricing points for most of the month. Daily natural gas prices exceeded $3/MMBtu only in New England (Algonquin, $3.28/MMBtu), the Midwest (Chicago Citygates, $3.01/MMBtu), Southern CA (SoCal Border, $3.03/MMBtu), and Northern CA (PG&E Citygate, $3.33/MMBtu). Natural gas prices also dropped as low as $1.34/MMBtu in New England (Algonquin), $1.42/MMBtu in New York City (Transco Z6 NY), and $1.03/MMBtu in the Mid-Atlantic (Tetco M-3) during the month.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Electricity system daily peak demand was very high across the country in August. All-time peak demand records were set in Southern Company, which reached 48,142 MW on August 17, and in Texas (ERCOT), which reached 69,783 on August 10. Daily peak demand exceeded ERCOT's previous all-time record of 68,379 MW on six consecutive non-weekend days between August 5-12, peaking at 69,783 MW on August 11. Even during the weekend of August 8-9, daily peak demand exceeded 66,000 MW, nearly exceeding the previous all-time record level. Temperatures in Texas during early August can often be very high and this year was no exception. Houston high temperatures exceeded 100 degrees from August 6-11 and set a new record of 106 degrees on August 11. Dallas set new daily high temperature records of 107 degrees on August 10 and 105 degrees on August 11.

California (CAISO) set a new 12-month demand high of 46,822 MW on August 28, though this is well short of CAISO's all-time peak demand record of 50,270 MW, a level that may be hard to reach again due to increasing levels of distributed generation and energy efficiency and demand response measures in California. New England (ISONE), New York State (NYISO), the Mid-Atlantic (PJM), the Midwest (MISO), and Tucson Electric were all within 5% of 12-month high demand peak levels during the month.

In the Northwest, Bonneville Power Administration (BPA) was an outlier with low daily peak demand levels. BPA daily demand peaked at just 7,522 MW on August 19 and set a new 12-month peak demand low of 5,410 MW on August 29. August 29 was a Saturday, when electricity demand is typically lower than during the week, and temperatures averaged 66 degrees in Seattle and 70 degrees in Spokane, weather warm enough that no heating was needed and yet cool enough that no air conditioning was necessary.


Electric Power Sector Coal Stocks: August 2015


In August, U.S. coal stockpiles decreased to 158 million tons, down 1% from the previous month. This decrease in July-to-August coal stockpiles follows the normal seasonal pattern whereby coal stockpiles decrease during the summer months. Despite this decrease, coal stockpiles are still at relatively high levels due to a loss in market share to natural gas in all regions of the country.

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 77 days to 83 days of forward-looking days of burn estimates. For subbituminous units largely located in the western United States, the average number of days of burn also increased, going from 66 days in July to 73 days in August. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn decreased from the previous month, going from 8.8% in July to 6.8% in August. This is a much lower percentage than last August, when over 22% of units had less than 30 days of burn.

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

  August 2015   August 2014   July 2015  
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 5,938 100   5,906 90 0.5% 6,735 112 -11.8%
  Subbituminous 780 216   345 129 126.0% 762 217 2.3%
South Bituminous 30,486 82   28,137 74 8.3% 30,694 73 -0.7%
  Subbituminous 5,504 61   5,251 54 4.8% 5,865 63 -6.2%
Midwest Bituminous 14,704 82   11,195 61 31.3% 14,762 75 -0.4%
  Subbituminous 36,662 67   24,538 41 49.4% 36,809 59 -0.4%
West Bituminous 5,231 69   4,425 55 18.2% 5,364 68 -2.5%
  Subbituminous 30,832 84   17,210 44 79.1% 31,668 76 -2.6%
U.S. Total Bituminous 56,359 83   49,663 70 13.5% 57,555 77 -2.1%
  Subbituminous 73,777 73   47,345 44 55.8% 75,105 66 -1.8%

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


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 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.

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 combusion 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.