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Electricity Monthly Update

With Data for May 2015  |  Release Date: July 27, 2015  |  Next Release Date: August 25, 2015

Previous Issues

Highlights: May 2015

  • The Northeast and MidAtlantic had the largest increase in net generation compared to the previous May, as many states in these regions experienced significantly above average or record temperatures during May 2015.
  • 12-month low wholesale electricity prices were set in the Midwest (MISO), Louisiana (into Entergy), the Southwest (Palo Verde), and Southern California (CAISO) due to very low natural gas prices.
  • Hawaii's retail electricity revenue per kilowatthour fell the most of any state for the fifth month in a row, down 24% from last May.

Key Indicators

  May 2015 % Change from May 2014
Total Net Generation
(Thousand MWh)
321,906 -0.7%
Residential Retail Price
(cents/kWh)
12.95 0.9%
Retail Sales
(Thousand MWh)
285,707 -0.9%
Cooling Degree-Days 126 5.0%
Natural Gas Price, Henry Hub
($/MMBtu)
2.91 -38.0%
Natural Gas Consumption
(Mcf)
764,989 13.3%
Coal Consumption
(Thousand Tons)
57,309 -10.5%
Coal Stocks
(Thousand Tons)
174,558 27.9%
Nuclear Generation
(Thousand MWh)
65,833 4.6%



Residential solar PV capacity surpasses commercial solar PV capacity in 2014

This article uses net metering capacity data from Form EIA-826 "Monthly Electric Utility Sales and Revenue Report with State Distributions," which collects data on installed PV solar capacity as reported by electric utilities as facilities that participate in their net metering programs. The respondents of this survey represent a sample of electric utilities in the US and therefore this data underestimates the total amount of net metered capacity.

For the first time, residential photovoltaic (PV) capacity has surpassed commercial PV capacity. According to preliminary EIA data, in the third quarter of 2014, residential PV capacity exceeded commercial PV capacity by 5.7%.This gap widened to 11.4% by the fourth quarter of 2014.

In 2014, the average quarterly growth of solar PV capacity was 11% in the residential sector compared to a 6% average quarterly growth in the commercial sector. The number of net metering customers in 2014 showed a 10% average quarterly growth in the residential sector and a 5% average quarterly growth in the commercial sector. According to the Solar Energy Industries Association (SEIA), "ongoing strength in the residential sector and volatility in the non-residential market spurred this historic milestone." (Source: SEIA).

Residential solar surpasses commercial solar beginning in the second quarter of 2014. Residential solar PV capacity increased by 52% from second quarter 2013 to second quarter 2014, while commercial solar PV capacity increased by 29% over that period. The number of residential meters installed during that period grew by 48% versus 26% in the commercial sector.

The Solar Energy Industry Association (SEIA) states that, "Though the availability of capital for non-residential solar has vastly increased over the past five years, it has remained exceedingly difficult to finance and develop small commercial solar projects. These projects often have varying contract terms, power purchasers without credit ratings or easily assessed creditworthiness, and site-specific project requirements." (Source: SEIA).

Source: U.S. Energy Information Administration, Monthly Electric Utility Sales and Revenue Report with State Distributions (Form EIA-826)


At the state level in 2014, California continued to lead, with 37% growth in installed residential solar PV capacity and meters, followed by 32% growth in Arizona, and 20% growth in Hawaii. California also accounted for more than 50% of the solar residential meters installed in the United States as of 2014. Declining costs are a possible reason for the increase in residential solar PV capacity and the number of meters installed. National Renewable Energy Laboratory (NREL) states that, "Sustained growth can be attributed to a precipitous decline in installed system prices spurred by declining equipment costs and increasing productivity - all signs of a maturing solar industry." Also, SEIA states that, "with prices decreasing, solar companies have created new and better ways to make solar available and attractive to more customers. In the residential market, the advent of financial solutions including power-purchase agreements (PPAs), leases, and increasingly solar-optimized loans has opened up a wide swath of demand that previously did not exist." (Source: SEIA).

Top 5 States for Residential PV
(as of 12/31/2014)
State Capacity (MW) Number of Meters
United States 3,276 611,218
California 1,560 317,249
Arizona 314 49,959
Hawaii 231 49,946
New Jersey 206 28,357
New York 165 25,644
Source: U.S. Energy Information Administration, Monthly Electric Utility Sales and Revenue Report with State Distributions (Form EIA-826)

In the commercial sector in 2014, solar PV capacity grew by 16% in California, 4% in New Jersey, and 30% in Massachusetts, the three largest states in terms of installed commercial PV capacity and meters. The growth in Massachusetts is , in part, the result of several large retailers in Massachusetts adopting solar, including Walmart, Staples, Bed, Bath and Beyond, and IKEA (Source: SEIA).

Top 5 States for Commercial PV
(as of 12/31/2014)
State Capacity (MW) Number of Meters
United States 2,939 41,044
California 732 10,175
New Jersey 608 4,106
Massachusetts 363 2,033
Arizona 247 1,723
New York 144 3,520
Source: U.S. Energy Information Administration, Monthly Electric Utility Sales and Revenue Report with State Distributions (Form EIA-826)

Principal Contributor:

Lolita Jamison
(Lolita.Jamison@eia.gov)

 

End Use: May 2015


Retail rates/prices and consumption

In this section, we look at what electricity costs and how much is purchased. Charges for retail electric service are based primarily on rates approved by state regulators. However, a number of states have allowed retail marketers to compete to serve customers and these competitive retail suppliers offer electricity at a market-based price.

EIA does not directly collect retail electricity rates or prices. However, using data collected on retail sales revenues and volumes, we calculate average retail revenues per kWh as a proxy for retail rates and prices. Retail sales volumes are presented as a proxy for end-use electricity consumption.

Average revenue per kWh by state



Average revenue per kilowatthour figures were up in 30 states this May when compared to last year. Though not entirely uniform, most of these states are located in the West, northern Midcontinent, and Northeast regions. Three states had increases larger than 10% from last May, with two New England states leading the way. Connecticut was up 12% and Massachusetts up 11% from last year, with Idaho recording the third largest increase at just under 11%. Montana, New Hampshire (both up 7%) and Maine (up 5%) were also up over 5% on the month.

Average revenue per kilowatthour figures were lower in 20 states and the District of Columbia. Hawaii, for the fifth month in a row, is the state with the largest year-over-year decline, down nearly 24%, as significantly lower world oil prices continue to benefit the state's petroleum-heavy bulk power system. The majority of the other states trending lower this May are located in the lower Midcontinent and Southeast regions.

Total average revenues per kilowatthour were 10.21 cents in May, down slightly (-0.2%) from last year. The residential sector was the only sector up from last May (+0.9%), while the Commercial (-1%), Industrial (-1.3%) and Transportation (-0.9%) sectors were all down compared to last year.

Total retail sales volumes were down slightly this month, falling 0.9% to 285,707 GWh and were down in each individual sector. Of the three main sectors, Industrial was down the most, -1.7% to 80,356 GWh, followed by a -0.6% decline in the Residential sector to 94,922 GWh and a -0.5% decline to 109,819 GWh in the Commercial sector, which was also the largest sector by sales volumes during the month of May.

Retail sales



May electric industry retail sales volumes generally mirrored weather patterns and was split largely by the Mississippi River, with most states west of the Mississippi down compared to last year and a large number of states east of the Mississippi up from last year. The largest retail sales declines occurred in Arizona, down over 7%, and Nebraska and Washington, both of which were down nearly 7% for the month. Kansas, Louisiana and North Dakota were the only states in the continental U.S. west of the Mississippi to record retail sales volume increases during the month. New Jersey had the largest year-over-year increase, up 12% in May, followed by the District of Columbia, West Virginia, Virginia, and Maryland, all up 5% to 7% for the month.


As evidenced in retail sales volumes, Cooling Degree Day (CDD) trends in May were generally split across the Mississippi River. CDDs were down in all states across the West except in Washington, Texas, and Louisiana, and were up in most states east of the Mississippi, particularly in the Northeast. States from Pennsylvania to the north and east are shaded grey due to a low CDD baseline for the month, obscuring record average temperatures in that region. Connecticut, Massachusetts, Rhode Island, and Vermont experienced their warmest May's on record and Maine, Vermont, New York, New Jersey, Pennsylvania, Delaware, and Maryland had one of their five warmest May's on record.

 

Resource Use: May 2015

Supply and fuel consumption

In this section, we look at the resources used to produce electricity. Generating units are chosen to run primarily on their operating costs, of which fuel costs account for the lion's share. Therefore, we present below, electricity generation output by fuel type and generator type. Since the generator/fuel mix of utilities varies significantly by region, we also present generation output by region.

Generation output by region



map showing electricity regions

Net generation in the United States decreased 0.7% compared to May 2014. At the regional level, the Central and West regions saw net generation decrease by 2.6% and 7.7%, respectively, as both of these regions experienced cooler temperatures in May 2015 compared to the previous May, leading to a decreased need for electricity demand. All other parts of the country saw an increase in net generation, except for Texas, which saw net generation stay relatively flat when compared to the previous year.

Electricity generation from coal decreased in all regions of the country, except for the West, where coal generation increased by 1.0%% compared to May 2014. Electricity generation from natural gas increased in all parts of the country, with the Mid-Atlantic and Northeast seeing the largest percent increases in natural gas generation. These two regions experienced large increases in natural gas generation due to significantly above average temperatures in May 2015, with Vermont, Massachusetts, Connecticut, and Rhode Island experiencing record temperatures during the month.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in May 2014 and May 2015 by region and shows that changes in coal consumption for electricity generation were very similar to changes seen in electricity generation from coal.

The second tab compares natural gas consumption by region and shows that all regions of the country saw an increase in natural gas consumption.

The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. In May 2015, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption compared to the previous year.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were 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 chart above. For the first time in five months, the monthly average price of natural gas at Henry Hub increased from the previous month, going from $2.67/MMBtu in April 2015 to $2.91/MMBtu in May 2015. The natural gas price for New York City (Transco Zone 6 NY) also increased from the previous month, going from $2.30/MMBtu in April 2015 to $2.67/MMBtu in May 2015.

The New York Harbor residual oil price decreased slightly from the previous month, going from $10.25/MMBtu in April 2015 to $10.18/MMBtu in May 2015. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.

A fuel price comparison based on equivalent energy content ($/MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. For the fifth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. However, because of the month-to-month increase in the price of natural gas at Henry Hub, the spread between the two prices decreased significantly. The spread between the New York City gas price and the price of Central Appalachian coal also decreased compared to the previous month, with the New York City gas price still below the price of Central Appalachian coal, but by only $3.16/MWh.

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: May 2015

The United States has many regional wholesale electricity markets. Below we look at monthly and annual ranges of on-peak, daily wholesale prices at selected pricing locations and daily peak demand for selected electricity systems in the Nation. The range of daily prices and demand data is shown for the report month and for the year ending with the report month.

Prices and demand are shown for six Regional Transmission Operator (RTO) markets: ISO New England (ISO-NE), New York ISO (NYISO), PJM Interconnection (PJM), Midwest ISO (MISO), Electric Reliability Council of Texas (ERCOT), and two locations in the California ISO (CAISO). Also shown are wholesale prices at trading hubs in Louisiana (into Entergy), Southwest (Palo Verde) and Northwest (Mid-Columbia). In addition to the RTO systems, peak demand is also shown for the Southern Company, Progress Florida, Tucson Electric, and the Bonneville Power Authority (BPA). Refer to the map tabs for the locations of the electricity and natural gas pricing hubs and the electric systems for which peak demand ranges are shown.

In the second tab immediately below, we show monthly and annual ranges of on-peak, daily wholesale natural gas prices at selected pricing locations in the United States. The range of daily natural gas prices is shown for the same month and year as the electricity price range chart. Wholesale electricity prices are closely tied to wholesale natural gas prices in all but the center of the country. Therefore, one can often explain current wholesale electricity prices by looking at what is happening with natural gas prices.

Wholesale prices



Selected wholesale electricity pricing locations

Wholesale electricity prices remained towards the lower end of the yearly range in May despite some moderate electricity system peak demand levels. This is in large part due to sustained low, and in some regions very low, natural gas prices that are a major determinate of wholesale electricity prices. Natural gas prices set a new 12-month low in New England (Algonquin) on May 26 of $1.61/MMBtu and were even lower in the Mid-Atlantic (Tetco M-3) at $1.43/MMBtu. The highest price recorded at the ten selected hubs during the entire month was a paltry $3.06/MMBtu. As natural gas-fired generators set marginal power prices in many areas of the country much of the time, these low natural gas prices invariably lead to low electricity prices. New 12-month low wholesale electricity prices were set in the Midwest (MISO), Louisiana (into Entergy), the Southwest (Palo Verde), and Southern California (CAISO), and just missed annual lows in most other regions. Peak power prices for the month remained below $40/MWh in all regions except for the Mid-Atlantic (PJM) and New York City (NYISO), $73/MWh and $67/MWh, respectively.

Electricity system daily peak demand


Electric systems selected for daily peak demand

May is sometimes not thought of as a shoulder month, but this May exhibits shoulder-season tendencies, with daily peak loads stretched from 12-month lows well up into the top quartile of all-time peak loads in many regions due to volatile weather patterns. On the low end, daily electricity system peak loads set 12-month lows in New England (ISONE), New York State (NYISO), and the Mid-Atlantic (PJM), and was very close in the Bonneville Power Administration. On the high end, daily high peak loads were up considerably in May from April, except in California (CAISO) and the Bonneville Power Administration, as one of the warmest May's on record east of the Mississippi River led to healthy May demand levels. Southern Company, Progress Florida, Texas (ERCOT), and Tucson Electric all had peak load days in May close to 80% of their all-time peak demand, with New York State (NYISO), the Mid-Atlantic (PJM), and the Midwest (MISO) close behind.

 

Electric Power Sector Coal Stocks: May 2015

 



In May, U.S. coal stockpiles increased to 175 million tons, up 4% from the previous month. This increase in April-to-May coal stockpiles follows the normal spring pattern where coal stockpiles are usually built up for use in the summer months. The spring build-up of coal stock piles started early this year, as the country experienced significantly above-average temperatures during the previous month, which led to a decreased demand for heating during March 2015 and thus, a decreased need for electricity generation. Coal has also lost market share to natural gas in all regions of the country.

Days of burn




The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn declined from 76 days to 74 days of forward-looking days of burn estimates. For subbituminous units largely located in the western United States, the average number of days of burn decreased, going from 77 days in April to 71 days in May. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn remained relatively flat, going from 5.6% in April to 5.3% in May. This is a much lower percentage than last May, when over 16% of units had less than 30 days of burn.

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

  May 2015   May 2014   April 2015  
Zone Coal Stocks (1000 tons) Days of Burn   Stocks (1000 tons) Days of Burn % Change of Stocks Stocks (1000 tons) Days of Burn % Change of Stocks
Northeast Bituminous 6,638 84   4,978 53 33.4% 6,085 81 9.1%
  Subbituminous 797 242   410 60 94.5% 795 262 0.3%
South Bituminous 34,920 72   30,658 59 13.9% 33,827 76 3.2%
  Subbituminous 7,066 75   6,028 57 17.2% 6,927 79 2.0%
Midwest Bituminous 15,723 73   12,097 53 30.0% 14,853 73 5.9%
  Subbituminous 40,938 64   31,615 48 29.5% 39,109 70 4.7%
West Bituminous 6,698 74   6,158 67 8.8% 6,458 75 3.7%
  Subbituminous 35,008 80   21,879 50 60.0% 34,745 86 0.8%
U.S. Total Bituminous 63,980 74   53,891 58 18.7% 61,223 76 4.5%
  Subbituminous 83,809 71   59,932 49 39.8% 81,575 77 2.7%

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 are proprietary and non-public.

Key Indicators

The Key Indicators in the table located in the "Highlights" section, are defined below. The current month column includes data for the current month at a national level. The units vary by statistic, but are included in the table. The "% Change from 2010" value is the current month divided by the corresponding month last year (e.g. July 2011 divided by July 2010). This is true for Total Generation, Residential Retail Price, Retail Sales, Degree-Days, Coal Stocks, Coal and Natural Gas Consumption.  The Henry Hub current month value is the average weekday price for the current month. The Henry Hub "% Change from 2010" value is the average weekday price of the same month from 2010 divided by the average weekday price of the current month.

Total Net Generation:  Reflects the total electric net generation for all reporting sectors as collected via the Form EIA-923.
Residential Retail Price:  Reflects the average retail price as collected via the Form EIA-826.
Retail Sales:  Reflects the reported volume of electricity delivered as collected via the Form EIA-826.
Degree-Days:  Reflects the total population-weighted United States degree-days as reported by the National Oceanic and Atmospheric Administration.
Natural Gas Henry Hub:  Reflects the average price of natural gas at Henry Hub for the month.  The data are provided by Bloomberg. 
Coal Stocks:  Reflects the total coal stocks for the Electric Power Sector as collected via the Form EIA-923.
Coal Consumption:  Reflects the total coal consumption as collected via the Form EIA-923.
Natural Gas Consumption:  Reflects the total natural gas consumption as collected via the Form EIA-923.
Nuclear Outages:  Reflects the average daily outage amount for the month as reported by the Nuclear Regulatory Commission's Power Reactor Status Report and the latest net summer capacity data collected on the EIA-860 Annual Generator Report.

Sector Definitions

The Electric Power Sector comprises electricity-only and combined heat and power (CHP) plants within the North American Industrial Classification System 22 category whose primary business is to sell electricity, or electricity and heat, to the public (i.e., electric utility plants and Independent Power Producers (IPPs), including IPP plants that operate as CHPs). The All Sectors totals include the Electric Power Sector and the Commercial and Industrial Sectors (Commercial and Industrial power producers are primarily CHP plants).

Degree Days

Degree-days are relative measurements of outdoor air temperature used as an index for heating and cooling energy requirements. Heating degree-days are the number of degrees that the daily average temperature falls below 65° F. Cooling degree-days are the number of degrees that the daily average temperature rises above 65° F. The daily average temperature is the mean of the maximum and minimum temperatures in a 24-hour period. For example, a weather station recording an average daily temperature of 40° F would report 25 heating degree-days for that day (and 0 cooling degree-days). If a weather station recorded an average daily temperature of 78° F, cooling degree-days for that station would be 13 (and 0 heating degree days).

Per Capita Retail Sales

The per capita retail sales statistics use 2011 population estimates from the U.S. Census Bureau and monthly data collected by the Energy Information Administration. The volume of electricity delivered to end users for all sectors in kilowatthours is divided by the 2011 population estimate for each state.

Composition of Fuel Categories

Net generation statistics are grouped according to regions (see Electricity Monthly Update Explained Section) by generator type and fuel type. Generator type categories include:

Fossil Steam:  Steam turbines powered by the combustion of fossil fuels
Combined Cycle:  Combined cycle generation powered by natural gas, petroluem, landfill gas, or other miscellaneous energy sources
Other Fossil:  Simple cycle gas turbines, internal combusion turbines, and other fossil-powered technology
Nuclear Steam:  Steam turbines at operating nuclear power plants
Hydroelectric:  Conventional hydroelectric turbines
Wind:  Wind turbines
Other renewables: All other generation from renewable sources such as geothermal, solar, or biomass
Other:  Any other generation technology, including hydroelectric pumped storage

Generation statistics are also displayed by fuel type. These include:

Coal:  all generation associated with the consumption of coal
Natural Gas:  all generation associated with the consumption of natural gas
Nuclear:  all generation associated with nuclear power plants
Hydroelectric:  all generation associated with conventional hydroelectric turbines
Other Renewable: all generation associated with wind, solar, biomass, and geothermal energy sources
Other Fossil: all generation associated with petroleum products and fossil-dervied fuels
Other:  all other energy sources including waste heat, hydroelectric pumped storage, other reported sources

Relative Fossil Fuel Prices

Relative fossil fuel prices are daily averages of fossil fuel prices by month, displayed in dollars per million British thermal units as well as adjusted for operating efficiency at electric power plants to convert to dollars per megawatthour. Average national heat rates for typical operating units for 2010 were used to convert relative fossil fuel prices.

Average Days of Burn

Average Days of Burn is defined as the average number of days remaining until coal stocks reach zero if no further deliveries of coal are made. These data have been calculated using only the population of coal plants present in the monthly Form EIA-923. This includes 1) coal plants that have generators with a primary fuel of bituminous coal (including anthracite) or subbituminous, and 2) are in the Electric Power Sector (as defined in the above "Sector definitions"). Excluded are plants with a primary fuel of lignite or waste coal, mine mouth plants, and out-of-service plants. Coal storage terminals and the related plants that they serve are aggregated into one entity for the calculation of Average Days of Burn, as are plants that share stockpiles.

Average Days of Burn is computed as follows: End of month stocks for the current (data) month, divided by the average burn per day. Average Burn per Day is the average of the three previous years’ consumption as reported on the Form EIA-923.

These data are displayed by coal rank and by zone. Each zone has been formed by combining the following Census Divisions:

  • Northeast — New England, Middle Atlantic
  • South — South Atlantic, East South Central
  • Midwest — West North Central, East North Central
  • West — Mountain, West South Central, Pacific Contiguous

Coal Stocks vs. Days of Burn Stocks

The coal stocks data presented at the top of the Fossil Fuel Stocks section (“Coal Stocks”) will differ from the coal stocks presented in the Days of Burn section (“DOB Stocks”) at the bottom of the Fossil Fuel Stocks section. This occurs because Coal Stocks include the entire population of coal plants that report on both the annual and monthly Form EIA-923. The DOB Stocks only include coal plants that report on the monthly Form EIA-923 and have a primary fuel of bituminous (including anthracite) or subbituminous as reported on the Form EIA-860.