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Electricity Monthly Update

With Data for February 2014  |  Release Date: Apr. 22, 2014  |  Next Release Date: May 21, 2014

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Highlights: February 2014

Key Indicators

  February 2014 % Change from February 2013
Total Net Generation
(Thousand MWh)
323,662 4.6%
Residential Retail Price
(cents/kWh)
11.88 2.1%
Retail Sales
(Thousand MWh)
308,997 7.0%
Heating Degree-Days 812 9.7%
Natural Gas Price, Henry Hub
($/MMBtu)
6.04 76.1%
Natural Gas Consumption
(Mcf)
573,014 -3.4%
Coal Consumption
(Thousand Tons)
76,350 13.7%
Coal Stocks
(Thousand Tons)
118,949 -32.2%
Nuclear Generation
(Thousand MWh)
62,639 1.9%
Nuclear Outages
(MW)
8,525 -36.8%



Solar-electric Generating Capacity Increases Drastically in the Last Four Years

U.S. solar capacity increased significantly in the last 4 years. In 2010, the total solar capacity was 2,326 MW which accounted for a comparatively small fraction (0.22%) of the total U.S. electric generating. capacity. By February 2014, this capacity increased 418% to 12,057 MW, a 9,731 MW gain, and now accounts for almost 1.13% of total U.S. capacity. Reported planned solar capacity additions indicate continued growth

EIA tracks three principal types of solar-electric generating capacity:

1. Residential and commercial rooftop and other photovoltaic (PV) capacity reported by distribution utilities as net-metered.

2. Utility level (>= 1 MW) solar photovoltaic capacity reported by generation operators.

3. Utility level (>= 1 MW) solar thermal capacity reported by generation operators.

Source: EIA-826, EIA-861, EIA-860, EIectric Power Monthly

Net metered applications, which are generally intended to displace retail purchased power to lower the overall energy bill for a host site, have increased each year since 2010 at an annual rate of about 1,100 MW and now total 5,251 MW. Although sunny California has the largest net metered solar capacity (38% of the total), abundant sunshine is not the only growth factor for this sector. Net metered applications are typically incentivized through various state level programs. New Jersey and Massachusetts together represent an additional 21% of the total net metered solar capacity. Overall, nationally the growth in net metered photovoltaic capacity is fairly evenly split between residential and commercial applications.

Utility scale PV applications, which are 1 MW or greater, have also expanded significantly and currently account for 5,564 MW. In 2013 utility scale solar exceeded the capacity of net metered applications. Utility scale PV applications generally provide wholesale electric power (although there are exceptions in the 1-3 MW range where some utility scale applications are net metered). The growth in utility scale PV applications is driven by many of the same factors behind net metered applications. Sunny states like California (2,702 MW, 49% of the total utility scale PV) and Arizona (960 MW, 17%) enjoy favorable siting conditions. However, North Carolina accounts for 340 MW or 6% of the total utility level solar capacity, and is the third leading state in this sector largely due to state incentives. While North Carolina has a modest net metered solar capacity, just 11.6 MW or 0.2% of the total net metered capacity, its large utility scale PV total indicates a diverse approach among state strategies to increase the level of renewable participation.

The third principal contributor to the large increase in solar capacity comes from thermal applications. These are distinct from PV applications in that solar energy is used to generate heat in a working fluid which is then converted to mechanical energy in a turbine then to electrical energy in a generator. Historically, the thermal solar application sector consisted primarily of a set of facilities near San Bernadino, California, SEGS I through SEGS IX, which account for 400 MW of capacity. The thermal solar sector expanded significantly in 2013 when three large plants, Solano, Genesis and Ivanpah, went on line adding a total of 650 MW of capacity. Solano is a particularly distinctive application in this sector due to its storage capability that extends the daily operating period and cushions sudden drops in output due to interruptions from passing clouds.

Each of the three sectors that have contributed to the significant overall solar gains also has strong near term growth prospects. Currently, there are 6,459 MW of proposed utility scale PV and 1,841 MW of proposed thermal solar. Many of the same factors driving utility-level solar are expected to push net metered capacity as well.

In summary, the U.S. solar capacity has moved quickly from a relatively small contributor to the nation's total electric capacity into a one of comparative significance. Much like the wind sector growth, which grew tremendously from 6,456 MW in January 2005 to 60,661 MW to January 2014, solar capacity is quite clearly up and coming.


Principal Contributor: Glenn McGrath
(Glenn.McGrath@eia.gov)

 

End Use: February 2014


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



In February, 45 out of 50 states, along with the District of Columbia, had average revenue per kWh figures higher than last February. Seven states, Pennsylvania, Maryland, Rhode Island, Kentucky, New York, Massachusetts, New Jersey and the District of Columbia had increases greater than 11%. Only West Virginia, Arkansas, Louisiana, Nebraska and Missouri had average revenue per kilowatt figures lower than last February, with the largest decrease of 3.89% found in West Virginia.

Average revenue per kWh levels were highest in Hawaii, followed by Northeastern states, Alaska and California. Average revenue per kWh levels were lowest in Arkansas, followed by Washington, Idaho, Louisiana and Wyoming.

Total average revenues per kilowatthour averaged 10.35 cents in February, up slightly from 10.13 cents in January, and up 5.7% from last February. The industrial sector had the largest increase from last year, 7.7%, followed by the commercial (6.3%) and residential (2.1%) sectors. All of these increases are significant and likely reflect the flow through to retail rates of some of the high wholesale electricity prices in February due to cold weather. (See discussion on the regional wholesale markets page.) The industrial sector is most directly affected by high wholesale prices. While residential customers are least affected.

Total retail sales volumes increased 7% from last February to 308,997 GWh, though this was down from January's 339,006 GWh total. Residential sales, the largest component of total, increased significantly compared to last February, up 15.6% to 130,478 GWh. This reflects the severe cold weather in February (see the heating degree day map below). Commercial sector sales were up 3.9% to 104,662 GWh, while industrial sector sales decreased 1.8% to 73,135 GWh when compared to one year ago.

Retail Sales



Electric industry retail sales volumes were mostly up in February 2014 when compared to February 2013. Texas had the largest increase in retail sales, up nearly 25%, with 11 other states logging double-digit increases.

Kentucky had the largest decrease of any state, down 7.5%, as the closure of a large energy consumer last year, the United States Enrichment Corporation facility in Paducah, Kentucky, continues to affect year-over-year comparisons. Arizona, Utah and Delaware also saw retail sales declines greater than 2% from last February.


In February, heating degree days (HDDs) were up significantly relative to both last year and to the long-term normal in most of the country, and were down significantly in the Southwest and Southeast.

39 out of 50 states and the District of Columbia had increases in HDDs this February when compared to last February. The largest increase occurred in Texas, up nearly 40% from last February. Louisiana and Montana were up over 30%, and ten other upper and lower midwestern states were up over 20%. Wisconsin, Iowa and Illinois all experienced one of their top 10 coldest February's on record.

On the other end of the spectrum, Arizona (down 48%), California, Florida (both down 29%), Utah (down 28%), New Mexico and Nevada (both down 24%), were all significantly warmer than last February. North and South Carolina, Georgia, Idaho and Colorado were the only other states to have decreased HDDs this February. Arizona, California and Utah all experienced one of their top 10 warmest February's on record.

 

Resource Use: February 2014

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 increased 4.6 percent in February 2014 compared to the previous year. This year-over-year increase in electricity generation occurred because most states in the U.S. experienced significantly lower temperatures this February compared to last February. This led to a significant increase in heating load compared to last year which, in turn, caused an increased demand for electricity generation during February 2014. For the second consecutive month, the only region that experienced a decrease in electricity generation compared to the previous year was the West, where heating degree days were significantly below those for last February (see the heating degree day map on the End Use page). This contributed to the West having a 1.1 percent decrease in electricity generation compared to last February.

Electricity generation from coal increased in all regions of the country, with Florida having the largest percentage increase in coal generation with a 65 percent rise compared to last February. The change in natural gas generation was much more varied, with the Northeast, Mid-Atlantic, Southeast, and Florida, all experiencing decreases in natural gas generation. In the Northeast and Mid-Atlantic this was likely due to very high natural gas prices at times pricing some gas-fired generators out of the wholesale market (see the Regional Wholesale Market page.) The Central, West, and Texas all experienced increases in natural gas generation compared to last February.

In February 2014, electricity generation from nuclear plants increased in almost all parts of the country, except for in the Mid-Atlantic and Central regions where nuclear generation was down from the previous year. Hydroelectric generation was down in all regions compared to the previous February.

Fossil Fuel Consumption by Region





map showing electricity regions

The chart above shows that the change in total coal consumption mirrored the change in electricity generation from coal.

The second tab compares natural gas consumption in February 2013 and February 2014 by region. This consumption pattern mirrored the change in electricity generation from natural gas, with the Southeast having the largest percent decrease in natural gas generation, with coal consumption increasing in all regions.

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. Coal increased its share of total fossil fuel consumption in all parts of the country, except for the West, at the expense of natural gas. For the second consecutive month, the Northeast saw "other fossil fuels" (mainly petroleum) significantly increase its share of total fossil fuel consumption at the expense of natural gas, due to the colder temperatures and higher natural gas prices that occurred in the region during February 2014.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis between February 2013 and February 2014 by region. Once again, 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 price of natural gas at Henry Hub increased significantly from the previous month, going from $4.78 / MMBtu in January 2014 to $6.04 / MMBtu in February 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased significantly from the previous month, but was still relatively high at $12.33 / MMBtu in February 2014. New York City's natural gas prices are often higher 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. However, the high natural gas prices in the Northeast and Chicago this winter were unprecedented.

The New York Harbor residual oil price increased from the previous month, going from $20.49 / MMBtu in January 2014 to $21.47 / MMBtu in February 2014. Despite this increase, because of higher natural gas prices, oil was able to increase its market share in February 2014 relative to last February.

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. Due to the significant increase in the price for natural gas, the spread between the Henry Hub and New York City natural gas prices continued to climb well above the price of Central Appalachian coal on a $ / MWh basis in February 2014.

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: February 2014

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 wholesale electricity prices in February were considerably lower in eastern and midwestern locations than in January, when 12-month range peak levels were set in New England, New York, the Mid-Atlantic, the Midwest and Louisiana. In New England, ISONE reached $236/MWh on February 28. On February 11, New York (NYISO) hit $227/MWh, the Mid-Atlantic (PJM) rose to $208/MWh and the Midwest (MISO) reached $111/MWh, all peak prices for the month. Though elevated, these prices are significantly lower than the $300/MWh to nearly $700/MWh peaks reached the previous month at those locations.

The lower peak electricity prices in February in these areas were largely a result of lower wholesale natural gas prices. In New England, Algonquin prices peaked at $31.50/MMBtu on February 28, down from a $78/MMBtu peak reached in January. In New York, Transco Zone 6-New York prices peaked at just under $25/MMBtu, down from a $121/MMBtu January high. In the Mid-Atlantic, Tetco M-3 prices peaked at $21/MMBtu on February 11, down from a $92/MMBtu peak in January. And in the Midwest, Chicago Citygates prices peaked at $23/MMBtu on February 6, down from a $33/MMBtu peak in January.

In Texas and the western U.S., wholesale electricity prices were considerably higher in February than in January and set twelve-month range highs in Texas (ERCOT), the Southwest (Palo Verde), Southern and Northern California and the Northwest (Mid-C). On Febuary 6, monthly peak prices were set in Texas ($185/MWh), the Southwest ($172/MWh), Northern CA ($135/MWh) and Southern CA ($131/MWh) and the Northwest ($218/MWh).

The higher peak wholesale electricity prices in Texas and the western U.S. in February reflected sharply higher wholesale natural gas prices in those areas, which were much higher than in January and set new high twelve-month ranges, as well as all-time high prices at several locations in the Rockies and Midwest. As with electricity prices, all peak February prices occurred on February 6. On that day, a large area of cold weather drove a spike in natural gas demand, resulting in a number of critical pipeline notices in the West and Midwest. Pipeline operators struggled to handle the increased demand levels while dealing with pipeline constraints, lower Canadian imports into the Northwest and natural gas storage levels depleted from the long winter. In Texas, prices exceeded $11/MMBtu at the Houston Ship Channel, in Southern CA, SoCal Border prices reached $21/MMBtu, and prices in the Southwest, Northern CA and the Northwest all approached $25/MMBtu.

Electricity System Daily Peak Demand


Electric systems selected for daily peak demand

Daily peak electricity system demand levels were lower in all regions in February from January except for Bonneville Power Administration (BPA) territory in the Pacific Northwest. BPA peak demand exceeded 10 GW from February 5-7, far above normal peak demand for the month, and the 10.6 GW high on February 6 set a new 12-month range high, though it did not approach BPA's 11.6 GW all-time peak. Demand was high in response to frigid weather, with high temperatures nearly 20 degrees below normal on the 6th.

On the opposite end of the spectrum, peak electricity demand levels were very low in Progress Florida, Tucson Electric and in California. Florida, California and the Southwest experienced one of the warmest February's on record, limiting electric demand for heating. These regions, as well as Texas (ERCOT) and Southern Company, recorded days in February with peak demand levels close to 12-month minimums.

 

Electric Power Sector Coal Stocks: February 2014

 



Extreme cold throughout the winter continued in February, leading to a 13.4 million ton decline in coal inventories from last month. Coal stocks have decreased 32.2 percent from February of last year. Total U.S. coal stocks in the electric power sector were at their lowest levels since March 2006. A combination of weather- and congestion-related delays have contributed to flat to declining receipts of coal at electric power plants throughout the fall.

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 bituminous supply decreased from 66 days the previous month to 61 days in February 2014, while the total subbituminous supply decreased from 50 days in January 2014 to 48 days in February 2014.

Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)

  February 2014   February 2013   January 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 3,278 42   7,040 70 -53.4% 4,280 42 -23.4%
  Subbituminous 249 72   251 35 -1.0% 202 20 23.2%
South Bituminous 29,925 64   49,051 96 -39.0% 35,308 75 -15.2%
  Subbituminous 3,059 33   6,732 71 -54.6% 3,275 36 -6.6%
Midwest Bituminous 10,608 49   15,710 73 -32.5% 11,474 48 -7.5%
  Subbituminous 25,457 43   41,834 71 -39.1% 27,819 44 -8.5%
West Bituminous 5,137 102   6,586 118 -22.0% 5,261 104 -2.4%
  Subbituminous 21,989 60   33,977 94 -35.3% 24,566 63 -10.5%
U.S. Total Bituminous 48,948 61   78,388 90 -37.6% 56,323 66 -13.1%
  Subbituminous 50,754 48   82,794 79 -38.7% 55,862 50 -9.1%

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 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.

For lists of the plants included in the calculations, the plants that are excluded, and the plants that are aggregated with terminals, contact EIA at EIA923@eia.gov.

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.