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Electricity Monthly Update

With Data for May 2014  |  Release Date: July 30, 2014  |  Next Release Date: August 25, 2014

Previous Issues

Highlights: May 2014

  • The lowest wholesale natural gas prices in the country were found in an unlikely place: the Northeast and Mid-Atlantic regions. The highest natural gas prices were found in California.
  • The New York City (Transco Zone 6 NY) natural gas price was $3.57/MMBtu in May 2014, which was $1.12/MMBtu below the price of natural gas at Henry Hub.
  • Electricity system daily peak demand was high in the CAISO and Tucson Electric systems as daily temperatures above 100 degrees increased cooling demand.

Key Indicators

  May 2014 % Change from May 2013
Total Net Generation
(Thousand MWh)
322,903 0.3%
Residential Retail Price
12.84 3.4%
Retail Sales
(Thousand MWh)
288,049 0.5%
Cooling Degree-Days 119 8.2%
Natural Gas Price, Henry Hub
4.69 12.8%
Natural Gas Consumption
672,659 5.0%
Coal Consumption
(Thousand Tons)
64,097 -1.0%
Coal Stocks
(Thousand Tons)
136,218 -22.9%
Nuclear Generation
(Thousand MWh)
62,116 -1.2%

Electricity consumption for irrigation affects average industrial electricity prices in farm states

Note: States vary significantly in their annual average revenues per kilowatthour (KWh). This measure is high for California and Northeastern states and low for Northwestern and Plains states. The factors that drive high or low average revenues per KWh are usually similar for the residential and industrial sectors. Thus, when states' residential and industrial average revenues per KWh are ranked, #1 being the highest, their residential and industrial ranks tend to be similar as seen in the chart. This similarity of ranks is not the case for the North Dakota, where the industrial rank is 18 and the residential rank is 51.
Source: U.S. Energy Information Administration, Electric Power Annual.

In some farm states, the average retail industrial prices (rates) appear high relative to those of other states because the electricity sold to power farm irrigation systems is categorized by electric utilities as industrial sector consumption. Irrigation systems can be costly to serve because of the high cost of connecting these dispersed loads to the electric grid and the high cost of having enough capacity available to meet seasonal irrigation load.

One way to see how agricultural use affects of industrial rates is by comparing state's ranks for average industrial and residential rates (which provides a baseline for retail rates in the state). For most states, these ranks are similar. These are the ones that appear close to the 45 degree diagonal line on the chart.

For other states, their average industrial rate rank is significantly higher than their average residential rate rank. The industrial rate ranks of North Dakota, Nebraska, and South Dakota are significantly higher than their residential rate ranks. In these states, agriculture is a significantly larger user of electricity than other types of industry.

For example, Dawson Public Power District, a rural electric cooperative in an agriculture-heavy region of Nebraska, accounted for less than 3% of statewide industrial electricity sales in 2012 but had one of the highest average prices for industrial power. In general, the highest industrial electricity prices in Nebraska tend to be located in the rural southern and western portions of the state.

Many agricultural-heavy electric utilities use demand-response programs to manage the costs of connecting a large number of small users to the grid. Nebraska's Dawson Public Power offers lower rates for agricultural customers who allow the utility to control the electric usage of these systems when demand for electricity is high, a form of demand response. This flexibility allows the grid operator to adjust the load shape in a given day and reduce the need to bring on more expensive sources of electricity generation .

Principal Contributors:

Bill Booth

Marc Harnish


End Use: May 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 May, 44 states and the District of Columbia had higher average revenue per kWh figures than last year. Rhode Island had the highest year-over-year average revenue per kWh increase at just over 14%, followed by Kentucky and Nevada, both up more than 10%. Several states spread out across the country (Louisiana, Idaho, Maryland, the District of Columbia, Alaska, Colorado, Tennessee, Kansas and Florida) had increases between 5-10%.

Six states had lower average revenue per kWh figures than last year. West Virginia had the greatest decrease of nearly 5%, followed by Michigan, down 4%. Delaware, Montana, Texas and Minnesota were down between 0-3% compared to last May.

Total average revenues per kilowatthour averaged 10.21 cents in May, 2.6% higher than last May and up slightly from April's average of 10.01 cents per kilowatthour. The residential sector increased the most, up 3.4% to 12.84 cents. The commercial sector had the next largest increase, up 2.4% to 10.51 cents. The industrial sector was up just slightly from last May, 0.9% to 6.76 cents. The transportation sector was the only sector to decline year-over-year, down 2.7% to 9.89 cents.

Total retail sales volumes increased 0.5% from last May to 288,049 GWh and was up across all sectors. Commercial volumes increased 0.8% to 109,713 GWh, residential volumes increased 0.6% to 95,507 GWh and industrial volumes increased 0.1% to 82,174 GWh. The transportation sector, by far the smallest of the four, had the biggest increase from last May, up 6% to 655 GWh.

Retail sales

In May, electric industry retail sales volumes varied widely by state, with nearly half the states higher and half lower relative to last year. The largest volume increase was found in North Dakota, up nearly 10%, with increased economic activity leading to increased electric demand. Other states with increases larger than 4% were clustered in the Southeast (North and South Carolina, Florida, Georgia) as well as Oklahoma, Kansas, Wyoming and New York.

As has been the case for several months now, Kentucky had the largest decrease of any state, down over 13%, as the closure of a large energy consumer last year, the United States Enrichment Corporation facility in Paducah, Kentucky, continues to affect year-over-year comparisons. The next largest retail sales decreases were found in New Jersey, down almost 7%, Delaware and Alaska, both down nearly 6%, and Idaho and Ohio, both down between 4-5% from last May.

Cooling degree days (CDDs), a measure of average daily temperatures above 65 degrees Fahrenheit, were generally higher in the Midcontinent and Southeast states (indicating warmer weather) and generally lower in the Northeast, Great Lakes and several Rocky Mountain states (indicating cooler weather) relative to last May.

The largest decreases, outside of Alaska, occurred in New York and all six New England states. The largest increases, outside of North Dakota, were found in Minnesota, California, Missouri, Kansas, Utah and several Southeast states.

When making CDD comparisons to long-term normal levels (second tab) for the month of May, North Carolina, South Carolina and Virginia had the largest increases. Louisiana, Michigan and Nevada had the largest CDD decreases relative to long-term normals.


Resource Use: May 2014

Supply and fuel consumption

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

Generation output by region

map showing electricity regions

In May 2014, net generation in the United States increased by 0.3 percent compared to May 2013. This slight increase in electricity generation follows the year over year increase of 8.2 percent in total cooling degree days when May 2013 is compared to May 2014 (see the cooling degree day map on the End Use page).

At the region-level, changes in electricity generation from the previous year were mixed. The Northeast, MidAtlantic, Central, and Texas all saw decreases in electricity generation compared to May 2013, while the Southeast, Florida, and West all saw increases in electricity generation.

Compared to the previous May, the only regions that saw a decrease in electricity generation from coal were the Central, MidAtlantic, and West regions. All regions of the country, except for the Northeast and Central, saw increases in electricity generation from natural gas compared to May 2013.

Total electricity generation from nuclear generators in the U.S. was down 1.2 percent compared to May 2013. The Southeast region had the largest decrease in nuclear generation due to maintenance or refueling outages at the V C Summer and Catawba nuclear plants in South Carolina and at the Waterford 3 nuclear plant in Louisiana. The change in electricity generation from hydroelectric generators was varied across the country, with the Southeast, Central and West all seeing decreases compared to last year, while the Northeast and MidAtlantic saw increases in hydroelectric generation compared to May 2013.

Fossil fuel consumption by region

map showing electricity regions

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

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

The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. Coal increased its share of total fossil fuel consumption by a slight margin at the expense of natural gas in the Central, Southeast, and Texas. Natural gas increased its share of total fossil fuel consumption at the expense of coal in the Northeast, MidAtlantic, West, and Florida.

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

Fossil fuel prices

To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $ / MMBtu basis as shown in the chart above. For the third consecutive month, the price of natural gas at Henry Hub decreased from the previous month, going from $4.78 / MMBtu in April 2014 to $4.69 / MMBtu in May 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased significantly from the previous month, going from $4.26 / MMBtu in April 2014 to $3.57 / MMBtu in May 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 third consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $18.60 / MMBtu in April 2014 to $17.77 / MMBtu in May 2014. Now that natural gas prices have decreased significantly since the winter months, oil used as a fuel for electricity generation is now 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 remained relatively the same compared to last month. However, because of the continued decrease in the New York City natural gas price, the spread between the price of Central Appalachian coal and the New York City natural gas price narrowed even further compared to last month.

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 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

Similar to April, daily wholesale electricity and natural gas prices traded in narrow bands towards the bottom of yearly ranges for the month of May. Electricity prices were highest in California, reaching $69/MWh in Southern CA (CAISO) and $68/MWh in Northern CA (CAISO) on May 13. As is often the case, electricity prices follow moves in natural gas prices and in May, the highest natural gas prices were found in California. Northern CA (PG&E Citygate) prices averaged $5.07/MMBtu, and were $0.25-0.45/MMBtu higher than the next highest priced point every day of the month. Southern CA (SoCal Border) was the next highest priced point and was higher than all other points except Northern CA for all but six trading days in the month.

The lowest electricity prices were found in the Northwest (Mid-C), which dipped to $19/MWh on May 24 and remained consistently lower than other pricing hubs for the majority of the month. The lower Northwest electricity prices come as no surprise since May is usually the beginning of peak hydroelectric season. One proxy for hydroelectric activity is measuring water flow at The Dalles Dam, a run-of-the-river dam on the Columbia River on the Washington/Oregon border. Flows at The Dalles Dam averaged 294 thousand cubic feet per second, up 28% from April's average flow, and reached 358 thousand cubic feet per second on May 27 (with daily data now through late July, that will most likely end up being the highest flow this year).

Possibly the most interesting wholesale price story for the month of May occurred in the Northeast. New York City (Transco Z6 NY) and Mid-Atlantic (Tetco M-3) had the lowest natural gas prices in the country for every day of the month, and by a wide margin. And beginning May 8, prices at New England (Alonguin) separated lower as well, and remained below the other pricing points for the rest of the month. This is a profound change in natural gas market dynamics.

The Northeast has long been known for having very high, and often the highest, natural gas prices in the country. But with sustained production growth in the Marcellus region, pipeline capacity has slowly increased as well, getting more and more of this production to key Northeast markets. Prices have begun to reflect this new reality, at least during non-peak demand periods when pipeline capacity is available, with Northeast natural gas prices now consistently lower than any other area in the U.S.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Coming as no surprise given typical monthly demand patterns, daily peak electricity system demand levels were higher in every region except Bonneville Power Administration in May compared to April. The highest loads occurred in the West, which has experienced warmer than normal temperatures for much of 2014. Tucson Electric had daily peak demand levels of 87% of their all-time peak on May 31, when high temperatures in Tucson reached 102 degrees, just short of the record for that day. California (CAISO) had daily peak demand levels of 83% of their all-time peak on May 15 due to extremely hot weather. High temperatures in Los Angeles set new records on May 14 (99 degrees) and May 15 (102 degrees), nearly 30 degrees higher than average. For the month of May as a whole, California had one of the top-10 warmest May's on record.

In the Northeast, New England (ISONE) and New York State (NYISO) daily peak demand levels remained below 70 percent of their all-time peaks. New England even set a new 12-month system peak low on May 25, just 46% of all-time peak. This was a result of three factors-May 25 was a Sunday during a holiday weekend (Sundays typically have lower demand) and the weather was extremely mild. Temperatures in Boston ranged from a low of 52 degrees to a high of 66 degrees, eliminating (or extremely limiting) the need for heating or cooling demand.


Electric Power Sector Coal Stocks: May 2014


Total U.S. coal stocks increased by 7.9 million tons compared to the previous month as the electric industry continues its spring build-up of coal stocks at power plants. However, compared to the previous May, total U.S. coal stocks are down 22.9 percent.

Days of burn

The average number of days of burn held at electric power plants is a forward looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. The total bituminous supply decreased from 55 days the previous month to 51 days in May 2014, while the total subbituminous supply decreased from 50 days in April 2014 to 46 days in May 2014.

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

  May 2014   May 2013   April 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 4,596 39   7,288 53 -36.9% 3,597 36 27.8%
  Subbituminous 410 38   465 32 -11.8% 344 49 19.0%
South Bituminous 32,298 51   50,972 77 -36.6% 30,872 54 4.6%
  Subbituminous 4,803 42   5,957 51 -19.4% 4,396 41 9.3%
Midwest Bituminous 13,754 50   15,832 57 -13.1% 13,154 57 4.6%
  Subbituminous 31,365 44   40,940 57 -23.4% 27,920 46 12.3%
West Bituminous 5,343 84   6,894 106 -22.5% 5,538 93 -3.5%
  Subbituminous 22,651 51   32,843 73 -31.0% 23,079 59 -1.9%
U.S. Total Bituminous 55,990 51   80,986 71 -30.9% 53,162 55 5.3%
  Subbituminous 59,230 46   80,205 62 -26.2% 55,739 50 6.3%

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.

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.