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Electricity Monthly Update

With Data for January 2015  |  Release Date: March 27, 2015  |  Next Release Date: April 27, 2015

Previous Issues

Highlights: January 2015

  • Heating Degree Days decreased 7.7% compared to last January, as the country experienced much warmer temperatures compared to last year.
  • Coal stockpiles increased 2% from the previous month. This deviates from the normal pattern usually observed during the winter months and is largely due to lower natural gas prices and the above average temperatures experienced in January 2015 throughout the country.
  • Southern Company set twelve-month maximum and reached 94% of all-time peak demand on January 8, 2015.

Key Indicators

  January 2015 % Change from January 2014
Total Net Generation
(Thousand MWh)
360,863 -4.4%
Residential Retail Price
12.10 3.9%
Retail Sales
(Thousand MWh)
325,682 -3.7%
Heating Degree-Days 895 -7.7%
Natural Gas Price, Henry Hub
3.09 -35.95%
Natural Gas Consumption
744,386 7.3%
Coal Consumption
(Thousand Tons)
71,518 -14.5%
Coal Stocks
(Thousand Tons)
155,115 16.1%
Nuclear Generation
(Thousand MWh)
74,270 1.7%

Average bills for residential customers rise in 2013

Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861)

For the first time since 2010, the average monthly electric bill for residential customers in the United States increased from the prior year. The movement from $107.28 in 2012 to $110.20 in 2013 represented a 2.7% increase in average bills. Between 2003 and 2010 average bills increased steadily before falling in 2011 and 2012. The 2.7% rise in average electric bills in 2013 was driven by a 2.1% increase in the average residential price of electricity and a 0.7% increase in average monthly electricity use per customer.

Average monthly bills are calculated as reported revenues divided by the number of customers. The declines in average monthly bills in 2011 and 2012 were driven by reductions in average consumption per customer despite increases in average electricity prices. The difference in 2013 stems from the fact that average consumption per customer rose at the same time that electricity prices increased resulting in higher average electricity bills.

The impacts of weather on average consumption per customer appear on balance to be somewhat muted. While heating degree days (HDD) increased by 9.9% in 2013 relative to 2012, cooling degree days (CDD) declined by 9.5% in 2013 compared to 2012. It is possible that the HDD increase added more to consumption than the CDD fall took away from it. Modest increases in personal income per capita (1.3%) may have also helped increase consumption. On the supply side, increases in the average cost of fossil fuel to power plants (9.2%), including a 26.6% increase in natural gas prices, added to the increase in average electricity prices.

Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861)

Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861)

The largest percentage increases in average bills are clustered in the upper Midwest states, as well as in certain pockets in the Northeast, Gulf States, and Rocky mountain states. The state that experienced the largest increase in the average monthly bill in 2013 was Louisiana, increasing from $104.99 to $119.98, an increase of 14.3%. Louisiana also had the highest increase in the average residential price of electricity in the United States, increasing 12.6% from 8.37 cents per kilowatthour to 9.43 cents per kilowatthour. Louisiana's residential average monthly bill ranks among the highest in the nation, where three-fifths of all households use electricity for home heating. Per capita retail sales of electricity in Louisiana are also among the highest in the nation. The primary fuel used for electricity generation in Louisiana is natural gas.

On the other hand, Illinois had the largest decrease in the residential average bill in the United States going from $87.20 in 2012 to $80.19 in 2013, an 8% decrease. This reduction was driven by decreases in both average consumption and average electricity prices. The average price of electricity in Illinois fell from 11.38 cents per kilowatthour in 2012 to 10.63 cents per kilowatthour in 2013, a 6.6% reduction. This reduction in average residential rates could be driven in part by the increased availability of alternative retail electricity suppliers. According to the Illinois Commerce Commission, through 2013, almost 3 million residential consumers had chosen to use an alternative electric supplier, compared with about 1.8 million in January 2013.

Top Ten Highest and Lowest Average Residential Electricity Bills

Excluding Hawaii, which normally has the highest bills because its electricity rates are more than three times the national average, seven of the top ten states with the highest average residential bills are southern states (Alabama, South Carolina, Texas, Mississippi, Virginia, Georgia, and Tennessee). This result is mainly because that region has relatively high demand levels in part because of significant cooling demand. These southern states have higher bills despite the fact that their rates are below the national average. The other three states in the top ten are Maryland, Connecticut, and Delaware.

Top ten highest average residential electricity bills
State Number of customers Average monthly consumption (kWh) Average price (cents/kWh) Average monthly bill ($)
Hawaii 422,386 514.71 36.98 190.36
Maryland 2,218,948 1030.83 13.25 136.63
Alabama 2,158,898 1211.21 11.26 136.36
South Carolina 2,135,432 1124.38 11.99 134.86
Texas 9,954,303 1174.30 11.35 133.33
Connecticut 1,454,963 752.34 17.55 132.07
Mississippi 1,260,892 1220.20 10.78 131.49
Virginia 3,273,502 1156.16 10.84 125.36
Georgia 4,101,351 1087.94 11.46 124.67
Tennessee 2,738,547 1244.76 9.98 124.25
Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861)

The ten states with the lowest bills include nine states (New Mexico, Maine, Illinois, Utah, Colorado, Montana, California, District of Columbia, and Wyoming) where consumption per customer is lower than the national average. Washington has lower bills as a result of their abundant hydro resources.

Top ten lowest average residential electricity bills
State Number of customers Average monthly consumption (kWh) Average price (cents/kWh) Average monthly bill ($)
New Mexico 865,195 655.34 11.68 76.56
Maine 704,775 551.28 14.35 79.13
Illinois 5,120,607 754.67 10.63 80.19
Utah 981,194 798.50 10.37 82.79
Colorado 2,169,365 711.76 11.93 84.91
Montana 477,266 860.19 10.33 88.85
California 13,359,503 557.15 16.19 90.19
District of Columbia 235,322 720.15 12.57 90.51
Washington 2,880,008 1041.19 8.70 90.55
Wyoming 263,614 894.46 10.16 90.85
Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861)

Principal Contributor:

Jorge Luna-Camara


End Use: January 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 up in 31 states, down in 17 states and the District of Columbia, and flat in two states in January. The largest year-over-year increase was found in Massachusetts, which was up almost 14%. Two other New England states, Connecticut and New Hampshire, had the next largest increases at 10% and 9%, respectively. The largest year-over-year decline was found in Hawaii, which was down nearly 12% in January. This is an interesting development, and one not entirely unexpected given world events. Hawaii relies on imported petroleum for the vast majority of its electricity generation and would seem to be a prime beneficiary of the large decline in world oil prices over the last six months. Average revenue per kilowatthour figures have fallen from 34.08 cents in September 2014 to 30.04 cents in January 2015, though these figures remain considerably higher than any other state.

Total average revenues per kilowatthour were 10.19 cents in January, 0.6% higher than last year. This marks the 26th straight month with year-over-year increases. Pricewise, changes were mixed by sector, with the residential and transportation sectors higher, and the commercial and industrial sectors lower than last year.

In regards to retail sales volumes, January volumes totaled 325,682 GWh, which was down 3.7% from last January. All sectors showed declines, with the residential sector down 6.4%, the commercial sector down 2.5%, and the industrial sector down just 0.1%. The transportation sector, by far the smallest of the four, was down 11.1% in January.

Retail sales

In January, as is often the case, electric industry retail sales volumes corresponded closely to weather. The vast majority of states experienced a warmer January than last year (which was one of the coldest on record for states east of the Mississippi River), and a vast majority of states had lower retail sales volumes than last year. Also, most of the states that had the largest decline in heating degree days this January, in the Southeast, also tended to have the largest declines in retail sales volumes.

Twelve states and the District of Columbia had sales volume declines greater than five percent. DC led the way with a decline of 8.45%, followed by Kentucky, Missouri, Alabama, Georgia, and Arkansas, which were all down 6-7%. Just eight states had electric industry retail sales volume increases relative to last January. Nevada had the largest increase at 6.5%, followed by North Dakota and Arizona, both up 3-4%.

Heating degree days (HDDs) were lower in 38 states and the District of Columbia in January. Florida had by far the largest decline of any state, down 38%, with Alabama and Georgia next with HDD declines of just over 20%. There were 12 states that had higher HDDs this January compared to last year, and these states were concentrated in New England and the Southwest (and Montana and Alaska). Alaska had the largest year-over-year HDD increase, up 24%, followed by California (up 23%) and Arizona (up 14%).


Resource Use: January 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

Net generation in the United States decreased 4.4% compared to January 2014 as most of the country experienced warmer temperatures compared to last year, which led to a decreased demand for heating compared to last January. These warmer temperatures were evident in the 7.7% decrease in total U.S. population-weighted heating degree days compared to last January. At the regional level, the only region of the country that did not see a decrease in net generation due to the warmer temperatures, was Texas, where below average temperatures caused a slight increase in net generation compared to last year.

In January 2015, electricity generation from coal decreased in all parts of the country compared to last January. Natural gas generation increased in all parts of the country compared to last year, except for in the West, where a significant increase in hydroelectric generation displaced the need for natural gas generation. Electricity generation from other fossil fuels, mainly oil, was down compared to last January, particularly in the Mid-Atlantic, where temperatures were warmer than January 2014.

Fossil fuel consumption by region

map showing electricity regions

The chart above compares coal consumption in January 2014 and January 2015 by region and shows that coal consumption for electricity generation has decreased in all regions of the country.

The second tab compares natural gas consumption by region. All regions of the country saw an increase in natural gas consumption, except for the West, which saw a substantial decrease in natural gas consumption. This decrease in the West's natural gas consumption occurred because of the increased electricity generation coming from hydroelectric power plants in January 2015, thus displacing the need for natural gas consumption used for electricity 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. The West was the only part of the country that saw a slight increase in coal consumption at the expense of natural gas. All other parts of the country saw an increase in natural gas at the expense of coal and in both the Northeast and Mid-Atlantic, natural gas also increased its share of fossil fuel consumption compared to other fossil fuels, which is mainly oil.

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 very 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 monthly average price of natural gas at Henry Hub decreased from the previous month, going from $3.45/MMBtu in December 2014 to $3.06/MMBtu in January 2015. However, the natural gas price for New York City (Transco Zone 6 NY) saw an increase in price from the previous month, going from $3.31/MMBtu in December 2014 to $8.66/MMBtu in January 2015. This increase in New York City's natural gas price is often observed during this time of year when there is an increased demand for natural gas used for heating in an area of the country where the natural gas pipeline infrastructure is subject to significant congestion.

For the sixth consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $11.36/MMBtu in December 2014 to $9.47/MMBtu in January 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. The price of natural gas at Henry Hub is now below the price of Central Appalachian coal on a $/MWh basis. This occurred due to the significant decrease in the Henry Hub price compared to last month. However, the spread between the New York City gas price and the price of Central Appalachian coal increased considerably due to the significant increase in New York City's gas price from the previous month.

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 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

January wholesale natural gas and electricity market prices were high, but not the highest in the past year. Not shown in the chart and the second tab chart above are the record-high prices that occurred last January. Peak electricity prices this January reached $124/MWh in New York City (NYISO), compared to $518/MWh last January, $110/MWh this January in New England (ISONE) compared to $438/MWh last January, $82/MWh in Mid-Atlantic (PJM) this January compared to $683/MWh last January and reached only $41/MWh in the Midwest (MISO) compared to a $306/MWh peak reached last January.

Since wholesale natural gas prices typically drive wholesale electricity prices in these markets, it is no surprise that the lower electricity prices this January are coupled with much lower natural gas prices. Peak natural gas prices this January reached just over $18/MMBtu in New York City (Transco Zone 6-NY), compared to $121/MMBtu last January, reached just over $14/MMBtu in New England (Algonquin) this January compared to $78/MMBtu last January, nearly $17/MMBtu in the Mid-Atlantic (Tetco M-3) compared to $92/MMBtu last January, and just $3.46/MMBtu in the Midwest (Chicago Citygates) compared to $33/MMBtu there last January.

These lower prices were a result of several factors. First, unlike last year, this January did not see extended, extremely cold weather blanket large parts of the U.S. and thus, there was not extended periods of extremely high energy demand across large regions of the country. Second, higher levels of liquefied natural gas deliveries into New England, increased domestic natural gas production, and incremental increases in pipeline capacity moderated natural gas prices to a degree. Lastly, winter preparedness programs implemented or augmented as a result of last winter's experience led to increased communication between operators and between natural gas and electric industry participants and lower levels of forced generator outages.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Daily peak electricity system demand highs were set in many regions on January 8, as cold weather spread across much of the country. Southern Company set an annual twelve-month maximum and reached 94% of all-time peak load levels on this day. Monthly demand peaks were also set then in New England (ISONE), the Mid-Atlantic (PJM), the Midwest (MISO), Progress Florida, and Texas (ERCOT), though none approached levels seen on the Southern Company system. Record low temperatures in cities such as Charlotte, NC, Atlanta, GA, and Dallas, TX drove up electricity demand as a higher percentage of residential heating systems in these areas are electric compared to heating systems in the Northeast and Midwest.


Electric Power Sector Coal Stocks: January 2015


In January, total U.S. coal stockpiles increased 2%, or nearly 4 million tons, to 155 million tons from the previous month. This increase in coal stockpiles deviates from the normal pattern usually observed during the winter months, when coal consumption for electricity generation usually outpaces the delivery of coal received at power plants due to the need to meet winter heating demand. The warmer than average temperatures experienced throughout the country in December 2015 and January 2015 helps explain the increase in coal stockpiles, as there was less of need to consume coal for electricity generation to meet the demand for heating. Also, the significantly lower price for natural gas made coal a less competitive fuel source in some regions. Coal stockpiles increased 16% over levels observed last January.

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. The total days of burn at bituminous units increased from the previous month, going from 79 days in December to 81 days in January. On average, the days of burn at subbituminous units increased from 58 to 69 days of burn. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn fell from 8% in December 2014 to 4% in January 2015.

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

  January 2015   January 2014   December 2014  
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 7,049 91   5,244 68 34.4% 7,513 86 -6.2%
  Subbituminous 779 203   129 17 505.3% 475 82 64.0%
South Bituminous 33,064 85   33,501 87 -1.3% 35,188 85 -6.0%
  Subbituminous 6,184 82   4,587 57 34.8% 6,352 78 -2.7%
Midwest Bituminous 14,363 73   9,906 49 45.0% 14,426 68 -0.4%
  Subbituminous 33,409 57   28,629 49 16.7% 31,939 51 4.6%
West Bituminous 5,349 70   5,793 77 -7.7% 5,421 65 -1.3%
  Subbituminous 28,839 82   24,301 68 18.7% 25,773 68 11.9%
U.S. Total Bituminous 59,824 81   54,445 74 9.9% 62,549 79 -4.4%
  Subbituminous 69,210 69   57,646 56 20.1% 64,539 58 7.2%

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 is proprietary and non-public.

Key Indicators

The Key Indicators 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, Cooling 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.
Cooling Degree Days:  Reflects the total population weighted U.S. 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.  This data is 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 (IPP), including IPP plants that operate as CHP). 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 unit 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 primary fuel of lignite and 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.