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Electricity Monthly Update

With Data for January 2014  |  Release Date: Mar. 21, 2014  |  Next Release Date: Apr. 21, 2014

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Highlights: January 2014

  • The New York City natural gas price ($28.02/MMBtu) exceeded the price of New York Harbor Residual Oil ($20.49/MMBtu) in January 2014.
  • Electricity generation from oil increased significantly in the Northeast at the expense of natural gas due to the extremely cold weather experienced in the region during the month.
  • New York State (NYISO), the Mid-Atlantic (PJM), Southern Company in the Southeast, and the Mid-West (MISO) all recorded new all-time winter peak demands in January 2014.

Key Indicators

  January 2014 % Change from January 2013
Total Net Generation
(Thousand MWh)
377,019 8.2%
Residential Retail Price
11.65 1.6%
Retail Sales
(Thousand MWh)
339,006 6.8%
Heating Degree-Days 970 17.3%
Natural Gas Price, Henry Hub
4.78 38.6%
Natural Gas Consumption
689,214 4.3%
Coal Consumption
(Thousand Tons)
83,710 11.6%
Coal Stocks
(Thousand Tons)
132,324 -26.0%
Nuclear Generation
(Thousand MWh)
73,064 2.3%
Nuclear Outages
3,498 -60.5%

Major Shifts in Regional Electric System Operations

On December 19, 2013, the Entergy electric system and 14 other balancing authorities (BA) near the gulf coast were absorbed into the system of the MidContinent Independent System Operator (MISO). On March 1, 2014 the Southwest Power Pool (SPP) assumed the balancing function for 17 of its member systems. This is the biggest shakeup in regional operating electric systems in recent years.

Source: U.S. Energy Information Administration

Note: Thirteen balancing authorities (ovals) that merged into MISO are not shown for clarity.

Source: U.S. Energy Information Administration

The number of entities in the U.S. that perform the balancing function has declined significantly. Twenty years ago these control areas, now called balancing authorities (BA), numbered roughly 150. In the late 1990s, a number of BAs were absorbed into the newly created California Independent System Operator and Electric Reliability Council of Texas systems. The PJM Interconnection has absorbed a number of BAs over the past decade. On January 6, 2009, MISO assumed the balancing function for about 30 of its member systems. There are currently 68 BAs operating in the lower 48 states.

EIA has adjusted how it presents its regional resource use data due to Entergy and other embedded or adjacent BAs joining MISO. Previously, most of these BAs were included in the Southeast region (see the yellow region on the first map). Now these BAs are included in the Central region (see green region on the second map). For the regional generation and fuel use charts on the Electricity Monthly Update Resource Use page, EIA uses the current alignment of BAs for the current month and the same month last year.

The reduction of many BAs to one in SPP does not change how EIA presents regional resource data since SPP was and remains in the Central region.

Principal Contributor: Bill Booth


End Use: January 2014

Retail Rates/Prices and Consumption

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

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

Average Revenue per kWh by state

In January, 45 out of 50 states and the District of Columbia had average revenue per kWh figures higher than last January. Rhode Island had the highest increase, up almost 29%, and Kentucky, Georgia, Nevada, Maine and New Jersey all had increases greater than 10%. Only Arkansas, Louisiana, Hawaii, West Virginia and Tennessee had average revenue per kilowatt figures lower than they recorded last January, with the largest decrease of 3.59% found in Arkansas.

Changes in state's average revenue per kilowatthour values are due to a number of market and regulatory factors. Price changes in the wholesale energy markets markets have little immediate effect on retail revenues. In a month like January where much of the country endured extended cold weather, high energy demand and high wholesale energy prices, the effect on retail customers may not be immediate or consistent across states. Customers will experience varying price sensitivity as a result of fuel pass-through clauses, retail choice contract provisions and rate case schedules, among other factors.

Total average revenues per kilowatthour averaged 10.13 cents in January, up from 9.88 cents in December and an increase of 4.9% from last January. The industrial sector had the largest increase from last year, 7.9%, followed by the commercial (5.6%) and residential (1.6%) sectors. The transportation sector, a small component of total, was up 0.5% from last January. Average revenues were highest in the residential sector, at 11.65 cents per kilowatthour, followed by the commercial sector at 10.34 cents per kilowatthour. The industrial sector, even with the largest year-over-year increase of the sectors, had the lowest average revenue levels in January at 6.96 cents per kilowatthour.

Total retail sales volumes increased 6.8 percent from last January to total 339,006 GWh. This was also up nearly 8% from December sales levels of 314,076 GWh. The retail sales volumes increase this January is due to the much colder weather most of the country experienced. The residential sector, most sensitive to low temperatures, had an 11.5% increase in retail sales volumes from last January while commercial sector volumes rose 6.4%. The industrial sector, more immune to changes in temperature, was down 0.7% from last January.

Retail Sales

Electric industry retail sales volume changes in January mirrored weather patterns. States in the western U.S. experiencing above normal temperatures this winter saw a decrease in retail sales volumes. Arizona, Idaho, and Nevada, all had retail sales volumes decreases of greater than 4%. States in the eastern U.S. and in particular the Southeast, where temperatures remained well below normal for the month, had retail sales volume increases. West Virginia, Georgia, Alabama, South Carolina, Virginia, North Carolina, North Dakota, and the District of Columbia all had increases of at least 10% from last January.

As mentioned last month, the closure of a United States Enrichment Corporation facility in Paducah, Kentucky is having a noticeable effect on Kentucky's retail sales volumes. This facility was a large consumer of electric power and its absence makes a noticeable difference in Kentucky's retail sales volumes, which were down 5.6% in January from a year ago, the largest decrease of any state.

Nationally, heating degree days (HDDs) in January were up 17% from last year. A consistent weather pattern developed in January and has continued through February and March, with those states east of the Rocky Mountains experiencing colder-than-normal weather and states to the west experiencing warmer-than-normal temperatures. All 11 states covering the Rockies and to the west in the continental U.S. had HDD totals down at least 6% from last January, with California leading the way with a decrease of nearly 47%.

This is in stark contrast with the eastern U.S., where states from Louisiana to Maryland experienced an increase in HDDs of at least 30% from last January. Florida had the largest increase in HDDs (220%), followed by Georgia (up 80%), Alabama (up 73%) and Louisiana (up 71%). The state east of the Mississippi River with the smallest increase in HDDs from last January was actually Maine, up only 4%.

The pattern is similar when looking at this January in relation to long-term normal levels (see the second tab). HDD levels were lower in the western U.S. and higher (and in many instances much higher) in states in the Midwest and eastern U.S.


Resource Use: January 2014

Supply and Fuel Consumption

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

Generation Output by Region

map showing electricity regions

Net generation in the United States increased 8.2 percent in January 2014 compared to the previous year. This year-over-year increase in electricity generation occurred because most states in the eastern half of the U.S. experienced significantly below normal temperatures in January 2014. This led to a significant increase in heating load compared to last year which caused increased demand for electricity generation during January 2014. The only region that experienced a decrease in electricity generation in January 2014 was the West, where the overall average temperature for many Western states was significantly above average for January. This caused the West to have a 4.4 percent decrease in electricity generation compared to last January.

For the second consecutive month, electricity generation from coal increased in all regions of the country except for the West. The change in natural gas generation was much more varied, with the Mid-Atlantic, Southeast, Florida, Central, and the West all experiencing increases in natural gas generation. The Northeast and Texas all experienced decreases in natural gas generation compared to last January. The Northeast had the largest percent change in natural gas generation, decreasing 17.2 percent compared to last January. The large decrease in natural gas generation in the Northeast can be attributed to the significantly colder temperatures experienced in January 2014, which led to a large increase in natural gas prices in the region that, on some days, effectively priced natural gas generation out of the market.

Electricity generation from nuclear plants increased in almost all parts of the country, except for in the Mid-Atlantic and Southeast where nuclear generation was down slightly from the previous year. Other fossil generators increased electricity generation in all regions of the country during January 2014, particularly in New England, the Mid-Atlantic and the Southeast. At times, it was cheaper to burn oil than natural gas.

Fossil Fuel Consumption by Region

map showing electricity regions

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

The second tab compares natural gas consumption in January 2013 and January 2014 by region. This consumption pattern mirrored the change in electricity generation from natural gas, with the Northeast having the largest percent decrease in natural gas generation.

The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. Coal increased its share of total fossil fuel consumption in the Southeast, Florida, and Texas at the expense of natural gas. The only regions that saw natural gas increase its share of total fossil fuel consumption at the expense of coal was the West. The Northeast saw "other fossil fuels" (mainly petroleum) significantly increase its share of total fossil fuel consumption at the expense of natural gas, due to the colder temperatures and higher natural gas prices that occurred in the region during January 2014.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis between January 2013 and January 2014 by region. Once again, the change in total coal and natural gas consumption was very similar to the change seen in total coal and natural gas net generation in each region.

Fossil Fuel Prices

To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $ / MMBtu basis as shown in the chart above. The price of natural gas at Henry Hub increased significantly from the previous month, going from $4.38 / MMBtu in December 2013 to $4.78 / MMBtu in January 2014. The natural gas price for New York City (Transco Zone 6 NY) experienced a significant increase from the previous month, going from $6.12 / MMBtu in December 2013 to $28.02 / MMBtu in January 2014.

Increases in New York City's natural gas price are often observed during this time of year when there is an increased demand for natural gas used for heating in an area of the country where the natural gas pipeline infrastructure is subject to significant congestion. However, the high natural gas prices in the Northeast and Chicago this January were unprecedented. The December-to-January price increases were particularly large this season because of the significantly colder temperatures experienced in the regions during the month, and the natural gas price actually exceeded the price of New York Harbor Residual Oil, which was $20.49 / MMBtu in January 2014.

A fuel price comparison based on equivalent energy content ($ / MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. Due to the significant increase in the price for natural gas, the spread between the Henry Hub and New York City natural gas prices climbed well above the price of Central Appalachian coal on a $ / MWh basis in January 2014. The New York City natural gas price climbed above the city's residual oil price on a $ / MWh basis, and helps explain the observed increase in the use of generators that use oil to produce electricity during January 2014.

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


Regional Wholesale Markets: January 2014

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

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

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

Wholesale Prices

Selected wholesale electricity pricing locations

Daily wholesale electricity prices in January reached levels seldom, if ever, seen at locations in the Midwest and eastern U.S. In ISONE, prices reached nearly $438/MWh on January 23. On January 28, prices exceeded $518/MWh in NYISO, $683/MWh in the mid-Atlantic (PJM) and reached almost $306/MWh in the Midwest (MISO). The elevated price levels were also notable due to the sustained levels at which they remained; this was not an isolated one or two day event.

Wholesale electricity prices were much lower by comparison in the western U.S. Prices peaked at $70/MWh in Texas (ERCOT) and remained below $55/MWh in the Southwest (Palo Verde), California and the Northwest (Mid-C).

There were two major factors contributing to the high wholesale electricity price levels seen in January. The first is the extremely high electricity demand, particularly for non-summer months, that occurred. Several regions set new all-time winter peak demand records and experienced extended periods of well-above normal demand levels for this time of year.

The second factor contributing to high wholesale electricity prices were the extremely high natural gas prices in several parts of the country (see second tab). In the Northeast, natural gas prices reached $78/MMBtu in New England (Algonquin), $121/MMBtu in New York City (Transco Zone 6-New York), $92/MMBtu in the mid-Atlantic (Tetco M-3) and $33/MMBtu in the Midwest (Chicago Citygates). These prices were high enough to incent the use of petroleum for electric generation, something rarely seen in recent years due to the relatively high price of petroleum products in relation to natural gas.

Electricity System Daily Peak Demand

Electric systems selected for daily peak demand

In the mid-Atlantic region, PJM set a new all-time winter peak record of 141,312 MW on January 7 and experienced eight of the highest 10 winter demand peaks during the month. In New York State (NYISO), a new all-time winter peak record of 25,738 MW was also recorded on January 7, breaking the previous winter peak record set nearly 10 years ago in December 2004. In the Southeast, Southern Company reached peak demand levels of 39,130 MW on January 7, exceeding the previous winter peak record of 37,224 MW set in January 2010. And in the Midwest, MISO set a new all-time winter peak record with demand exceeding 109,000 MW.


Electric Power Sector Coal Stocks: January 2014


In January 2014, total coal stocks decreased 10.6 percent from the previous month, and since January 2013, coal stocks have decreased 26.0 percent. This winter's extremely cold weather in the eastern half of the country has caused a draw-down of coal stockpiles at power plants due to increased coal consumption for electricity generation. Furthermore, there have been trade press reports that attribute the harsh weather for delivery delays and rail congestion that has reduced the ability of power plants to replenish their stockpiles to desired level.

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 63 days the previous month to 66 days in January 2014, while the total subbituminous supply increased from 48 days in December 2013 to 50 days in January 2014.

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

  January 2014   January 2013   December 2013  
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 4,280 42   7,414 62 -42.3% 5,224 40 -18.1%
  Subbituminous 202 20   448 27 -54.9% 282 19 -28.3%
South Bituminous 35,308 75   49,514 95 -28.7% 41,646 71 -15.2%
  Subbituminous 3,275 36   6,610 69 -50.5% 3,790 34 -13.6%
Midwest Bituminous 11,474 48   16,048 67 -28.5% 14,211 54 -19.3%
  Subbituminous 27,819 44   43,900 70 -36.6% 30,973 45 -10.2%
West Bituminous 5,261 104   7,176 127 -26.7% 5,637 94 -6.7%
  Subbituminous 24,566 63   33,337 87 -26.3% 25,233 58 -2.6%
U.S. Total Bituminous 56,323 66   80,151 87 -29.7% 66,718 63 -15.6%
  Subbituminous 55,862 50   84,295 75 -33.7% 60,279 48 -7.3%

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


The Electricity Monthly Update is prepared by the Electric Power Operations Team, Office of Electricity, Renewables and Uranium Statistics, U.S. Energy Information Administration (EIA), U.S. Department of Energy. Data published in the Electricity Monthly Update are compiled from the following sources: U.S. Energy Information Administration, Form EIA-826,“Monthly Electric Utility Sales and Revenues with State Distributions Report,” U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," fuel spot prices from Bloomberg Energy, electric power prices from SNL Energy, electric system demand data from Ventyx Energy Velocity Suite, and weather data and imagery from the National Oceanic and Atmospheric Administration.

The survey data are collected monthly using multiple-attribute cutoff sampling of power plants and electric retailers for the purpose of estimation for various data elements (generation, stocks, revenue, etc.), for various categories, such as geographic regions. (The data elements and categories are “attributes.”) The nominal sample sizes are: for the Form EIA-826, approximately 450 electric utilities and other energy service providers; for the Form EIA-923, approximately 1900 plants. Regression-based (i.e., “prediction”) methodologies are used to estimate totals from the sample. Essentially complete samples are collected for the Electric Power Monthly (EPM), which includes State-level values. The Electricity Monthly Update is based on an incomplete sample and includes only regional estimates and ranges for state values where applicable. Using ‘prediction,’ it is generally possible to make estimates based on the incomplete EPM sample, and still estimate variances.

For complete documentation on EIA monthly electric data collection and estimation, see the Technical Notes to the Electric Power Monthly. Values displayed in the Electric Monthly Update may differ from values published in the Electric Power Monthly due to the additional data collection and data revisions that may occur between the releases of these two publications.

Accessing the data: The data included in most graphics can be downloaded via the "Download the data" icon above the navigation pane.Some missing data is proprietary and non-public.

Key Indicators

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

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

Sector Definitions

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

Degree Days

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

Per Capita Retail Sales

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

Composition of Fuel Categories

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

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

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

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

Relative Fossil Fuel Prices

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

Average Days of Burn

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

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

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

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

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

Coal Stocks vs. Days of Burn Stocks

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