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Electricity Monthly Update

With Data for July 2014  |  Release Date: Sep. 25, 2014  |  Next Release Date: Oct. 24, 2014

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Highlights: July 2014

Key Indicators

  July 2014 % Change from July 2013
Total Net Generation
(Thousand MWh)
384,839 -2.3%
Residential Retail Price
(cents/kWh)
13.05 3.5%
Retail Sales
(Thousand MWh)
347,151 -2.4%
Cooling Degree-Days 308 -12.3%
Natural Gas Price, Henry Hub
($/MMBtu)
4.14 11.0%
Natural Gas Consumption
(Mcf)
870,103 -7.3%
Coal Consumption
(Thousand Tons)
81,631 -1.9%
Coal Stocks
(Thousand Tons)
125,389 -21.4%
Nuclear Generation
(Thousand MWh)
71,940 2.0%



Participation growth in Illinois residential retail choice programs has leveled off since March 2013

Source: Form EIA-826 "Monthly Electric Utility Sales and Revenue Report with State Distributions"


Starting in late 2011, residential customers in Commonwealth Edison (ComEd) and Ameren Illinois began an increasingly rapid migration from their regulated utilities to competitive retail suppliers for their electric supply. Residential retail choice participation rates increased from 2% in August 2011 to 62% in March 2013. This upward trend, however, leveled off beginning in March 2013. The upward growth of retail choice slowed and eventually peaked in February 2014, with participation rates at 69% and residential retail customers at 3.2 million. Since February 2014, both participation rates and retail choice customers have fallen to 66% and 3.0 million, respectively, in June 2014.

By February 2013, the number of switched customers exceeded the number of non-switched customers in these two service territories belonging to Illinois' two largest utilities. By August 2013, the number of switched customers was almost twice that of the non-switched customers.

Section 1-92 of the Illinois Power Agency Act allows for (under certain conditions) municipal aggregation of electric load, meaning that municipalities can contract for electric supply of its residents and eligible small businesses. Under these programs, regulated utilities still operate and maintain the infrastructure to deliver the electricity and coordinate billing: these costs constitute the "distribution charge" on a customer's bill. The third-party suppliers arrange for the supply of electricity, and it is this "commodity" or "energy" part of the bill where customers can potentially gain savings.

Retail electricity prices are particularly dependent on the level of natural gas prices. The decreasing natural gas prices from late 2011 to late 2012 helped competitive retail suppliers offer savings to customers compared to their regulated utility rates. During this time, Commonwealth Edison had older power purchase agreements (PPAs) that were above the market prices and not set to expire until May 2013.

Starting in June 2013, and with the expiration of older PPAs, the new "Price To Compare" for Commonwealth Edison fell from 8.5 cents/kilowatthour to 5.5 cents/kilowatthour, making it difficult for the alternate suppliers to provide meaningful savings to customers. Lower rates were also seen in the Ameren Illinois service territory.

Source: Illinois Commerce Commission, Plug In Illinois Historical Prices to Compare.
Note: Prices shown are residential non-space heating prices and include the electric supply charge and transmission services charge. Adjustment refers to each utility's monthly purchased electricity adjustment (PEA). The Ameren Illinois price shown is for Rate Zone I.


A complication in the analysis is that ComEd has a purchased electricity adjustment, or PEA, (see Historical Prices to Compare) that has ranged from a 0.5 cent credit to a 0.5 cent charge, further making it difficult to determine if an alternate supplier's price is creating savings for the customer. In addition, Ameren Illinois has a PEA that historically is a credit and normally under 2.0 cents/kilowatthour. ComEd's price to compare (which has been low after May 2013) has recently moved up. The Ameren Illinois price to compare has remained lower and not increased recently like the ComEd price.

One possible reason residential customers may have started to return to their regulated utilities is that FirstEnergy, a large alternate supplier to electric residential customers in Illinois, had proposed a customer surcharge for the unexpected and unusual costs associated with this winter's polar vortex. Based on clauses in the contracts, residential customers in some municipal aggregation groups can be charged for these types of expenses, bringing into question how much savings these types of programs are providing to customers and how much financial risk the customers may have unknowingly been exposed to.

After FirstEnergy's first proposal and the ensuing public reaction, they modified the surcharge to apply only to small commercial customers and decided to waive the requirement for residential customers.


Principal Contributor:

Carolyn Moses
(Carolyn.Moses@eia.gov)

 

End Use: July 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



July was the 20th month in a row where U.S. revenue per kilowatthour averages were higher than the same month of the previous year. It is also the first month where the all-sector average has exceeded 11 cents (11.01) cents per kWh. The increase has been fairly consistent, averaging 3% on a year-over-year basis over the 20-month period.

On an individual state level, 42 states had increases compared to last July. Rhode Island had the largest increase, up 17% to 14.36 cents per kWh, with Illinois also up just over 10% to 8.95 cents per kWh (see feature article). Only eight states and the District of Columbia had decreases compared to last July, with Michigan and West Virginia recording the largest decreases, down 5.2% and 4.5%, respectively.

Total average revenues per kilowatthour averaged 11.01 cents in July, 2.9% higher than last year and the first all-sector monthly average exceeding 11 cents. The commercial sector had the largest increase, up 3.7% to 11.16 cents per kWh. The residential sector, the largest in July by retail sales volumes, was up 3.5% to 13.05 cents per kWh and the first monthly average exceeding 13 cents, industrial sector posted a 2.3% gain over the previous year.

Total retail sales volumes were down 2.4% from last July, with the largest decrease occurring in the residential sector, down 5%. Residential sales volumes in the summer months are largely dependent on weather, with the length and severity of hot weather influencing the amount of climate control demand. This July, high temperatures across much of the U.S. were lower (and in some cases, far lower) than either last year or long-term normals.

Retail sales



No surprise here, as electric industry retail sales volume trends in July generally mirrored weather patterns. The largest year-over-year decreases in retail sales were found in the Northeast, Mid-Atlantic and Great Lakes states. These regions also experienced the largest decrease in cooling degree days compared to last July. The largest increase in retail sales volumes tended to be in Southeastern or Western states, which had more cooling degree days (CDDs) than last July, or in the case of far western states, one of the hottest July's on record.

Retail sales volume decreases were largest in Rhode Island, Connecticut and Massachusetts, all down more than 10%. This is only the second time (other than Maine last month) in almost a year that any state had year-over-year decreases larger than the state of Kentucky, which 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. Retail sales volumes were down so much in these three New England states as all had decreases in cooling degree days greater than 33% from last July.


In the central part of the country, states all the way from the Gulf of Mexico to the Great Lakes experienced one of their coolest July's on record. Arkansas and Indiana recorded their coolest July on record, Illinois, Mississippi and Missouri had their second coolest July on record, and Ohio, Iowa and Tennessee had their third coolest July on record. Kentucky, Alabama, Michigan and Oklahoma also had one of their top-seven coolest July's on record.

The one outlier in the central U.S. has been North Dakota. Despite a relatively cool July, with CDDs down 17% from last year and the 25th coolest on record, retail sales were up 5.25%, the largest increase of any state. This is due to the oft-reported boom in oil and gas activity in the state which has also driven up electricity demand.

 

Resource Use: July 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 decreased 2.3% in July 2014 compared to the previous year. This decrease in electricity generation occurred because temperatures as a whole were above average across the country last July, while temperatures in July 2014 were closer to average. This led to a decrease in demand for electricity generation in July 2014, with total population-weighted cooling degree days down 12.3% compared to July 2013. At the region-level, changes in electricity generation from the previous July were mixed. The Northeast, MidAtlantic, and Central regions all saw decreases in electricity generation compared to the previous year, while the West, Southeast, Texas, and Florida all saw increases in electricity generation.

Compared to the previous July, the change in electricity generation from coal was split throughout the regions. The Northeast, MidAtlantic, Central, and Texas all saw decreases in electricity generation from coal, while the Southeast, West, and Florida all saw increased coal generation. The change in electricity generation from natural gas was also split throughout the regions. The Northeast, MidAtlantic, Central, and West regions all saw decreases in natural gas generation, while the Southeast, Florida, and Texas all saw increases in electricity generation from natural gas.

Total electricity generation from nuclear generations in the U.S. was up 2.0% compared to July 2013. For the second consecutive month, the Central region had the largest percentage increase in nuclear generation compared to the previous year. This occurred because the Monticello and Fort Calhoun nuclear plants were offline in July 201 3 (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 July 2014. Electricity generation from hydroelectric generators was down 10.9% in the U.S. compared to last year, with all regions of the country, except for the Central region, experiencing a decrease in hydroelectric generation.

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 in each region.

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

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 at the expense of natural gas in the Central, Southeast, and West. The Northeast was the only region where natural gas significantly increased its share of total fossil fuel consumption at the expense of coal. In the MidAtlantic, Florida, and Texas, the shares of both coal and natural gas remained relatively flat compared to last July.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis between July 2013 and July 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 decreased from the previous month, going from $4.71 / MMBtu in June 2014 to $4.14 / MMBtu in July 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased for the sixth consecutive month, going from $3.39 / MMBtu in June 2014 to $2.73 / MMBtu in July 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 first time in four months, the New York Harbor residual oil price increased from the previous month, going from $17.44 / MMBtu in June 2014 to $17.78 / MMBtu in July 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 narrowed compared to last month, due to the decrease in the price of Henry Hub natural gas. However, because of the continued decrease in the New York City natural gas price, the price of Central Appalachian coal on a $ / MWh basis is now higher than the New York City natural gas price.

The conversion shown in this chart is done for illustrative purposes only. The competition between coal and natural gas to produce electricity is more complex. It involves delivered prices and emission costs, the terms of fuel supply contracts and the workings of fuel markets.

 

Regional Wholesale Markets: July 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

Wholesale electricity prices remained in tight ranges below $85/MWh at all hubs in July. These relatively moderate summer prices are largely the result of moderate natural gas prices, as natural gas-fired generators set the marginal price much of the time in RTO markets.

Several locations, New England (ISONE), New York City (NYISO), Mid-Atlantic (PJM), Midwest (MISO) and Southwest (Palo Verde), experienced peak prices on either July 1 or 2 and all points tended to trend down through the rest of the month. This is partially the result of peak monthly electricity demand, which was highest on July 1 or 2 in ISONE, NYISO, PJM and Southern, and partially the result of natural gas prices, which followed an even more pronounced steady, downward trend through the month of July. Prices in Louisiana at the Henry Hub, which is historically the main natural gas pricing point in the U.S., entered July at $4.43/MMBtu on July 1 and peaked at $4.47/MMBtu on July 2 before falling steadily to end the month at $3.78/MMBtu on July 31.

The correlation between natural gas and electricity prices is strong enough that the prices usually rise and fall in tandem. In New England, the peak monthly natural gas price at Algonquin ($4.93/MMBtu) and the peak monthly electricity price ($69.23/MMBtu) both occurred on July 1. In the Mid-Atlantic, the peak monthly natural gas price at Tetco M-3 ($3.89/MMBtu) and the peak monthly electricity price ($70.10/MMBtu) both occurred on July 2. And in the Midwest, the peak monthly natural gas price at Chicago Citygates ($4.49/MMBtu) and the peak monthly electricity price ($55.67/MWh) both occurred on July 1.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Daily peak electricity system demand levels for the year often occur in July. In fact, New York State (NYISO), Mid-Atlantic (PJM), Midwest (MISO), and California (CAISO) all recorded their all-time peak load levels in previous years during the month of July. This year, Tucson Electric set a new all-time peak demand record of 3,195 MW on July 23 in the middle of a triple-digit high-temperature heat wave. High temperatures of 103-104 degrees Fahrenheit on July 22-24 were seven degrees above average and high by even Tucson's lofty standards. More telling may be the average 24-hour temperature in Tucson on July 23, a sweltering 94 degrees for the day.

In areas other than Tucson Electric, though daily peak demand approached annual highs (or set an annual high in the case of ISONE and MISO), all regions fell well short of all-time peaks. July 2014 peak demand levels were 7%-35% below all-time peaks in all regions other than Tucson Electric. This is largely attributable to weather, as peak electricity demand levels are closely tied to maximum daily temperatures. This July was the 29th coolest average maximum temperature for the contiguous U.S. since 1895 according to the National Climactic Data Center. There may also be other factors at work. The recent, more widespread implementation of energy efficiency and demand response programs in many markets has undoubtedly dampened peak demand levels compared to the levels they could be without adoption of these programs.

 

Electric Power Sector Coal Stocks: July 2014

 



Total U.S. coal stocks decreased by 7.5 million tons compared to the previous month. This decrease in coal stocks follows the seasonal pattern where a significant decrease in coal stocks occurs between June and July as power plants consume more coal to meet increased electricity demand during the summer months. Furthermore, compared to the previous July, total U.S. coal stocks are down 21.4%. This large decrease in year-over-year stockpile levels is the result of increased coal-fired electricity generation during a long, cold winter across much of the U.S. and decreased coal deliveries due to lingering rail transportation issues. Certain coal-fired generators have been forced to deliver coal by truck and lower or completely idle output due to rail delivery problems. Record grain harvests in 2013 and 2014 and increasing shipments of petroleum products are in some cases contending with coal deliveries and have strained rail capacity on certain lines.

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 increased from 49 days the previous month to 53 days in July 2014, while the total subbituminous supply continued to decrease, going from 42 days in June 2014 to 39 days in July 2014.

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

  July 2014   July 2013   June 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 5,061 48   5,672 45 -10.8% 5,062 41 -0.0%
  Subbituminous 319 34   452 34 -29.4% 359 27 -11.1%
South Bituminous 29,092 51   45,058 84 -35.4% 30,783 48 -5.5%
  Subbituminous 4,360 38   4,825 42 -9.6% 4,631 39 -5.9%
Midwest Bituminous 13,092 51   14,923 58 -12.3% 13,596 47 -3.7%
  Subbituminous 26,895 38   37,977 55 -29.2% 29,375 40 -8.4%
West Bituminous 5,122 80   6,611 110 -22.5% 5,175 78 -1.0%
  Subbituminous 19,777 41   29,253 63 -32.4% 21,615 46 -8.5%
U.S. Total Bituminous 52,368 53   72,264 74 -27.5% 54,616 49 -4.1%
  Subbituminous 51,351 39   72,507 57 -29.2% 55,980 42 -8.3%

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.