‹ See all Electricity Reports

Electricity Monthly Update

With Data for June 2014  |  Release Date: Aug. 25, 2014  |  Next Release Date: Sep. 25, 2014

Previous Issues

Highlights: June 2014

  • June 2014 was the 19th month in a row where the average U.S. revenue per kilowatthour was higher than the same month of the previous year.
  • The New York City natural gas price, like many natural gas prices in the Northeast, was below the price of natural gas at Henry Hub in June 2014.
  • Demand for electricity on Tucson Electric's system reached 99.6% of all-time peak on June 30, 2014.

Key Indicators

  June 2014 % Change from June 2013
Total Net Generation
(Thousand MWh)
357,419 0.3%
Residential Retail Price
(cents/kWh)
13.14 4.8%
Retail Sales
(Thousand MWh)
319,310 0.6%
Cooling Degree-Days 238 -3.6%
Natural Gas Price, Henry Hub
($/MMBtu)
4.71 19.7%
Natural Gas Consumption
(Mcf)
745,369 -2.6%
Coal Consumption
(Thousand Tons)
74,579 -0.8%
Coal Stocks
(Thousand Tons)
132,885 -22.1%
Nuclear Generation
(Thousand MWh)
68,138 2.6%



Natural gas, solar, and wind led new power plant capacity additions in the first half of 2014

Source: U.S. Energy Information Administration, Electric Power Monthly, August 2014 edition with June 2014 data.
Note: Data include facilities with a net summer capacity of 1 MW and above only.


In the first six months of 2014, 4,350 megawatts (MW) of new utility-scale generating capacity came online. Natural gas plants, almost all combined-cycle plants, made up more than half of the additions, while solar plants contributed more than a quarter and wind plants around one-sixth.

These year-to-date additions were 40% less than the capacity added in the same period last year, which saw about 7,250 MW added. Natural gas additions were down by about half, while solar additions were up by nearly 70%. Wind additions in the first half of 2014 were more than double the level in the first half of 2013.

Florida added the most capacity (1,210 MW) of any state, all of it natural gas combined-cycle capacity. California, with the second-largest level of additions, added just under 1,100 MW, of which about 77% was solar and 21% was wind, with the remaining additions from natural gas and other sources. Utah, in third place, added 630 MW, all of it natural gas combined-cycle capacity. And Texas, in fourth place, added 350 MW, nearly all of it natural gas combined-cycle capacity with some solar and wind capacity.

Source: U.S. Energy Information Administration, Electric Power Monthly, August 2014 edition with June 2014 data.
Note: Data include facilities with a net summer capacity of 1 MW and above only.


Natural Gas

Additions of combined-cycle plants (2,180 MW) were up by 60% compared to the same period last year (1,380 MW).

Four plants accounted for the combined-cycle capacity additions — the new Riviera plant (1,212 MW) in Florida, expansions at the Lake Side Power Plant (629 MW) in Utah, and the Channel Energy Center (183 MW) and the Deer Park Energy Center (155 MW), both in Texas.

Significantly fewer combustion turbine plants were added (130 MW) compared to last year (3,120 MW), making the June 2014 year-to-date additions of natural gas plants overall about half the level of the same period last year.

Solar

Solar additions experienced strong year-on-year growth, with nearly 70% more additions in the first half of 2014 (1,150 MW) than in the same period last year (690 MW). About three-quarters of this solar capacity was located in California, with Arizona, Nevada, and Massachusetts making up most of the rest.

Notable additions include:

  • 152 MW of additional capacity at the Topaz PV plant in California
  • 134 MW of additional capacity at the Desert Sunlight PV plant in California
  • 125 MW of additional capacity at the Genesis solar thermal plant in California
  • 110 MW of additional capacity at the Agua Caliente PV plant (currently the largest solar PV plant in the world at 290 MW of total capacity) in Arizona
  • A combined 172 MW of capacity at the Solar Star 1 and Solar Star 2 PV plants in California

Wind

Wind additions (675 MW) were more than double the amount added in the same period last year (330 MW) and were concentrated in California, Nebraska, Michigan, and Minnesota.

California's 228 MW of capacity additions came from the Alta Wind X and Alta Wind XI projects of the Alta Wind Energy Center (currently the largest wind farm in the United States at 1,548 MW of total capacity), while Nebraska's 207 MW came from the Prairie Breeze wind farm. In Michigan, 61 MW of the Echo Wind Park plant came online as well as the 75-MW Pheasant Run II plant. In Minnesota, the 50-MW Lakeswind plant came online.

Other

In Washington, a 122-MW hydroelectric turbine came online at the Wanapum Dam to replace the 104-MW turbine that was retired in late 2013. The dam is in the middle of a decades-long project to replace all of its turbines (which date back to 1963-64) with new more-efficient turbines one at a time.

Coal

There were no additions of coal capacity so far in 2014. The two coal plants that came online last year, the 937-MW Sandy Creek Energy Station in Texas and the 571-MW Edwardsport integrated gasification combined-cycle (IGCC) plant in Indiana, were somewhat special situations of delayed coal projects finally coming online in 2013.

Apart from the Kemper IGCC plant in Mississippi, there are no other coal plants planned to come online in 2014.


Principal Contributors:

April Lee
(April.Lee@eia.gov)

 

End Use: June 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



June 2014 continued a streak as the 19th month in a row where U.S. revenue per kilowatthour averages were higher than the same month of the previous year. The increase has not been large, a 3% year-over-year difference on average over the 19-month period, but a persistent increase nonetheless.

Individually, forty-four states and the District of Columbia had higher average revenue per kWh figures than last April. The largest increase occurred in Illinois, where a sharp increase in PJM RTO capacity market prices for the 2014/2015 delivery year began June 1st (from $27.73/MW-day to $125.99/MW-day). This likely had some effect on retail electric bills in Illinois beginning in June. Alaska and Rhode Island also had increases larger than 10% from a year ago.

Total average revenues per kilowatthour averaged 10.89 cents in June, 4% higher than last year. Each sector increased, with the residential sector leading the way, up 4.8% to 13.14 cents per kilowatthour. The commercial sector climbed 3.6% to 11.09 cents per kilowatthour and the industrial sector increased 3.5% to 7.38 cents per kilowatthour.

Total retail sales volumes increased 0.6% from last April, totaling 319,310 GWh, in spite of a slight drop in residential sales volumes. The residential sector is very sensitive to changes in weather, and a cooler June across much of the country relative to last year suppressed climate control demand slightly. Both commercial and industrial sectors had higher sales volumes than last June, up 0.9% and 1.1%, respectively.

Retail sales



Electric industry retail sales volume trends generally mimicked weather patterns. In regions of the country where the weather was cooler than last summer, such as New England and the Rocky Mountain region, retail sales volumes decreased as air conditioning loads were likely lower. In areas of the country where the weather was warmer than last year, in the Southeast and Great Lakes region, retail sales volumes were higher.

North Dakota had the highest increase in retail sales volumes in June, up nearly 10% from last year, the third month in a row the state recorded the highest year-over-year increase. South Carolina, Washington and Iowa also had retail sales volume increases greater than 4%.

This month, the state with the largest year-over-year decrease in retail sales volumes was Maine, down 14%. This is the first month since September 2013 that a state other than Kentucky had the largest decline in sales volumes. Kentucky, down 7% in June relative to last year, continues to be affected by year-over-year comparisons related to the closure of a large energy consumer last fall, the United States Enrichment Corporation facility in Paducah, Kentucky.


When looking at cooling degree day (CDD) comparisons to last year, the weather was generally cooler in the Northeast and through much of the western US, and warmer than last year in the Southeast and Great Lakes region. The largest increase in year-over-year CDDs were found in Indiana, Ohio and Illinois, all up more than 19%. The states with the largest decreases in year-over-year CDDs were Montana, Wyoming, Maine, Oregon, Vermont and Rhode Island, all down more than 40%.

Relative to normal temperatures, June was generally warmer than normal across much of the U.S., with most states recording a higher-than-normal number of cooling degree days (CDDs). The top seven states with the highest increase in CDDs were located in the Southeast (North and South Carolina, Georgia, Virginia and Kentucky), the District of Columbia and West Virginia. The top five states with the lowest amount of CDDs relative to long-term normals were found in the upper Midwest and Rocky Mountain states (North and South Dakota, Wyoming, Montana and Nebraska).

 

Resource Use: June 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

In June 2014, net generation in the United States remained generally flat compared to June 2013, only increasing by 0.3 percent relative to the previous year. At the region-level, changes in electricity generation from June 2013 were mixed. The MidAtlantic and Southeast regions saw increases in electricity generation compared to the previous year, while Texas and the West all saw decreases in electricity generation. The Northeast, Central, and Florida all remained relatively flat compared to last June.

Compared to the previous June, the change in electricity generation from coal was split throughout the regions. The Northeast, West, and Texas all saw decreases in electricity generation from coal, while the MidAtlantic, Southeast, and Florida all saw increased coal generation. Electricity generation from coal in the Central region remained relatively flat, only increasing by 5,000 MWh compared to June 2013. The change in electricity generation from natural gas was also split throughout the regions. The Central, West, and Texas all saw decreases in natural gas generation, while the Northeast, MidAtlantic, Southeast, and Florida all saw increases in electricity generation from natural gas.

Total electricity generation from nuclear generations in the U.S. was up 2.6 percent compared to June 2013. The largest increase in electricity generation from nuclear came in the Central and West regions. In the Central region, the increase in nuclear generation occurred because the Monticello and Fort Calhoun nuclear plants were offline in June 2013 (and Fort Calhoun nuclear plant had been offline since May 2011 due to damage caused by severe flooding). Both nuclear plants were online and operating a normal capacity in June 2014. This is also what occurred in the West region, where the Columbia nuclear power plant was offline for refueling in June 2013 and operated at normal capacity in June 2014.

Electricity generation from hydroelectric generators was down 5.3 percent in the U.S. compared to last year, with all regions of the country, except for the Northeast, experiencing a decrease in hydroelectric generation. In June 2014, electricity generation from wind and other renewable generators showed an increase from the previous year. Both Texas and the West had the largest increases in wind and other renewable generation, due to the addition of many new wind and solar plants in those regions.

Fossil fuel consumption by region





map showing electricity regions

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

The second tab compares natural gas consumption in June 2013 and June 2014 by region. This consumption pattern mostly mirrored the change in electricity generation from natural gas, with the MidAtlantic region having the largest percentage increase in natural gas consumption and the Central having the largest percentage decrease.

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 by a slight margin at the expense of natural gas in the Central, Southeast, West, and Florida. Natural gas increased its share of total fossil fuel consumption at the expense of coal in the Northeast, MidAtlantic, and Texas.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis between June 2013 and June 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. For the first time in three months, the price of natural gas at Henry Hub increased from the previous month, going from $4.69 / MMBtu in May 2014 to $4.71 / MMBtu in June 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased for the fifth consecutive month, going from $3.57 / MMBtu in May 2014 to $3.39 / MMBtu in June 2014. Like many natural gas prices in the Northeast, the New York City natural gas price is now below the price of natural gas at Henry Hub. This is mainly due to the growth of natural gas coming out of the Marcellus region and a slight increase in pipeline capacity to the Northeast.

For the fourth consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $17.77 / MMBtu in May 2014 to $17.44 / MMBtu in June 2014. 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 spread between the Henry Hub natural gas price and the price of Central Appalachian coal on a $ / MWh basis widened slightly compared to last month, due to an increase in the price of Henry Hub natural gas and a decrease in the price of Central Appalachian coal. However, because of the continued decrease in the New York City natural gas price, both the price of Central Appalachian coal and the New York City natural gas price are relatively equivalent on a $ / MWh basis.

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: June 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

June typically marks the beginning of the peak summer demand period in US electricity markets. As temperatures and air conditioning use climbs, electricity demand-and prices-can rise as well. This June was largely absent any extreme heat events and with natural gas prices remaining below $5/MMBtu in all areas except Northern California (PG&E Citygate) and New England (Algonquin), wholesale electricity prices remained on the lower-end of the yearly range.

The highest daily wholesale electricity prices this month occurred in the Mid-Atlantic (PJM), with daily peak prices reaching $71/MWh on June 17 and $88/MWh on June 18. Unsurprisingly, these two days also had the highest peak electricity demand levels of the month. The highest daily peak prices for the month in New York City (NYISO) and New England (ISONE) also occurred on June 18 as an early summer heat-wave pushed daily high temperatures seven to twelve degrees Fahrenheit above normals for that day in Boston, New York City and Washington, DC, with temperatures nearing 100 degrees in Washington.

Daily wholesale natural gas prices traded in a tight band towards the low end of the yearly range for the month of June. In New England (Algonquin), New York City (Transco Z6 NY) and Mid-Atlantic (Tetco M-3), prices in late June set new twelve month lows, all well below $3/MMBtu, as low local natural gas demand, steadily increasing Marcellus area production and insufficient outward pipeline capacity depressed local natural gas prices in the Mid-Atlantic and Northeast regions. All other price locations traded between $4.05/MMBtu-$5.24/MMBtu during the month.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Daily peak electricity system demand levels were significantly higher in June than in May in all areas except California (CAISO), where the peak demand day was actually 3% lower than May's high and the Bonneville Power Administration, up just 2.5% from May. Peak daily demand was up 7% in Progress Florida and between 11%-32% in the other seven regions from May to June.

Tucson Electric nearly set a new all-time peak demand record on June 30, the third day of 100+ degree Fahrenheit temperatures. Peak demand reached 3,111 MW on that day, 99.6% of Tucson's all-time peak. On June 30, the last day of the month, New England (ISONE), New York State (NYISO), Southern Company, Texas (ERCOT), Tucson Electric, California (CAISO) and Bonneville Power Administration all logged their highest demand day for the month, hinting that higher loads were ahead for July.

 

Electric Power Sector Coal Stocks: June 2014

 



Total U.S. coal stocks decreased by 3.3 million tons compared to the previous month. This decrease in coal stocks follows the seasonal pattern from May to June as power plants begin to consume more coal to meet increased electricity demand during the summer months. Furthermore, compared to the previous June, total U.S. coal stocks are down 22.1 percent.

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 51 days the previous month to 49 days in June 2014, while the total subbituminous supply decreased from 46 days in May 2014 to 42 days in June 2014.

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

  June 2014   June 2013   May 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 5,062 41   7,208 52 -29.8% 4,596 39 10.1%
  Subbituminous 359 27   470 26 -23.6% 410 38 -12.4%
South Bituminous 30,783 48   48,508 77 -36.5% 32,298 51 -4.7%
  Subbituminous 4,631 39   5,147 44 -10.0% 4,803 42 -3.6%
Midwest Bituminous 13,596 47   15,639 54 -13.1% 13,754 50 -1.1%
  Subbituminous 29,375 40   40,249 54 -27.0% 31,365 44 -6.3%
West Bituminous 5,175 78   6,725 104 -23.0% 5,343 84 -3.1%
  Subbituminous 21,615 46   30,819 65 -29.9% 22,651 51 -4.6%
U.S. Total Bituminous 54,616 49   78,080 69 -30.1% 55,990 51 -2.5%
  Subbituminous 55,980 42   76,684 57 -27.0% 59,230 46 -5.5%

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.

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.