‹ See all Electricity Reports

Electricity Monthly Update

With Data for September 2014  |  Release Date: Nov. 25, 2014  |  Next Release Date: Dec. 23, 2014

Previous Issues

Highlights: September 2014

  • Total U.S. coal stocks are low compared to the past several years and compared to the previous September (down 18.4% year-over-year).
  • Total retail average revenues per kilowatthour was 10.80 cents in September, 3.5% higher than last year.
  • New England, New York, the Mid-Atlantic, California, and Tucson Electric all had higher daily peak electricity demand this September than occurred in August.

Key Indicators

  September 2014 % Change from September 2013
Total Net Generation
(Thousand MWh)
338,976 -0.4%
Residential Retail Price
(cents/kWh)
12.94 3.6%
Retail Sales
(Thousand MWh)
323,157 0.7%
Cooling Degree-Days 189 -2.1%
Natural Gas Price, Henry Hub
($/MMBtu)
4.04 8.6%
Natural Gas Consumption
(Mcf)
797,271 2.6%
Coal Consumption
(Thousand Tons)
69,293 -4.7%
Coal Stocks
(Thousand Tons)
124,176 -18.4%
Nuclear Generation
(Thousand MWh)
67,535 2.6%



The Use of Natural Gas Fired Internal Combustion Engines has Increased Significantly since 2002

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report


In October 2014, Sunflower Electric Power Corporation's 108 megawatt (MW) Rubart Power Plant in southwest Kansas was placed in commercial operation, roughly 18 months after ground was broken. The Rubart facility, consisting of 12 internal combustion (IC) engines fired by natural gas, joins a small but important group of power plants that use IC engine technology to provide significant generating capacity and grid support.

IC engines have traditionally been used in smaller plants located close to the loads they are intended to serve, and they have been fired by petroleum liquids (primarily distillate fuel oil). However, as shown in Figure 1, since 2002, natural gas-fired IC engines grouped together in larger facilities have been used to meet the demands of a changing electric power system, particularly in areas experiencing significant growth of wind capacity, where effective load following and fast startup capabilities are especially useful.

Several factors contributed to this growth. Historically, compression-ignition engines were the dominant stationary IC engine technology, which limited power generating IC engines to the use of petroleum liquids. Although dual-fuel engines (those that co-fire natural gas and a petroleum liquid pilot fuel) provided a bridge technology, engine manufacturers advanced spark- ignition IC engine technology such that large engines using natural gas are now commercially and operationally practical.

Manufacturers made these technology advancements in response to the same factors that drove the use petroleum liquids to less than 0.7% of the nation's electric power generation in 2013 (in 1990, petroleum liquids accounted for 4.2%). Natural gas is significantly less expensive than petroleum liquids and produces far lower emissions, particularly sulfur and particulate matter. Delivered through pipelines, natural gas does not require fuel inventory storage and management, which is an additional environmental and cost advantage.

In addition, IC engine technology has several performance and operational characteristics that are suitable for many grid applications. IC engines are often bundled in multiple unit applications. Engines can be operated to optimally serve either load-following or efficiency objectives. In load-following mode, multiple engines can operated from partial to full loads to accommodate changes in electricity demand. The ability of IC engines to load-follow is an increasingly important performance characteristic as the power system accommodates more intermittent resources such as wind and solar. In efficiency mode, select engines can be operated at their peak efficiency points, while others are idled and brought online only as needed. This strategic flexibility allows plant owners to react to different system and market requirements.

IC engines have competitive simple-cycle efficiencies, which means their fuel costs are generally not prohibitive. However, IC engines have other variable costs that tend to keep their capacity factors lower than average (12.1% versus 43.5 % for other technologies). Specifically, costly overhauls after 8,000 to 16,000 operating hours must be considered in plant dispatch decisions.

The recent commission of the Rubart plant shows that there is an increasing role for natural gas-fired IC engines. In January 2015, Portland General Electric's 222 MW Port Westward Unit 2 facility, which uses natural gas-fired IC engines, is expected to enter commercial operation. In the next four years, more than 95% of the 859 MW of proposed IC engine capacity will be fired by natural gas, indicating a clear trend within this niche technology.


Principal Contributor:

Glenn McGrath
(Glenn.McGrath@eia.gov)

 

End Use: September 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



September revenue per kilowatthour averages were up across most of the country, with 40 states higher and just 10 states and the District of Columbia down compared to last year. It also marks the 22nd month in a row of year-over-year national average revenue per kilowatthour increases.

Individually, the states with the largest average revenue per kilowatthour increases were geographically spread out throughout the country. Illinois, Rhode Island and California had the largest increases, all up over 10%. Alaska, Nevada, Connecticut, Florida, Oregon, Hawaii and Mississippi were also up more than 5%. States with the largest year-over-year decreases were West Virginia, down the most atnearly 5%, Maryland down 3% and New Jersey down almost 2%.

Total average revenues per kilowatthour was 10.80 cents in September, 3.5% higher than last year. All sector average revenues were up for the month, with the commercial sector having the largest increase, up 5.1% to 11.10 cents per kilowatthour, followed by the residential sector, up 3.6% to 12.94 cents per kilowatthour.

Total retail sales volumes totaled 323,157 GWh, up 0.7% from last September. Volumes were mixed by sector, with the residential and transportation sectors down slightly from last year and the commercial and industrial sectors up from last year.

Retail sales



As is usually the case, electric industry retail sales volumes in September generally mirrored weather patterns. Volumes were up along the coasts were cooling degree days were higher than last year and lower in the middle of the country where cooling degree days were also lower than last year.

Rhode Island had the largest increase, up over 10% from last year, followed by North Dakota (up 8%), Nevada (up 6%) and Maine (up 5%). North Dakota continues to be an outlier in regards to sales volumes not following weather patterns. The state has seen consistent sales growth due to robust economic growth in the state, even when weather conditions would indicate otherwise.

States that had sales decreases compared to last year line up nicely with those states that experienced lower levels of cooling degree days (CDD). Nebraska, South Dakota and Illinois had the largest sales decreases, all down more than 5%. These states also had very large drops in CDDs in September, all down more than 40%. Missouri, Kentucky, Minnesota and Oklahoma had decreases larger than 3% and also experienced significant declines in CDDs from last year.


Compared to September 2013, cooling degree days were higher along both coasts and lower in the middle of the country. Maine, New York, the District of Columbia, Nevada and Oregon all had CDD increases greater than 25%. All of the other states with CDD increases greater than 5% were near the eastern seaboard or the state of California. A bulls-eye of cooler weather centered over the upper Midwest, with Montana, Wisconsin, South Dakota and Nebraska all having CDD decreases greater than 50% from last year.

Relative to long-term averages, all but seven states were warmer than normal and California, Nevada and Utah had top-10 warmest Septembers on record.

 

Resource Use: September 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 September 2014, net generation in the United States decreased 0.4% compared to the previous year. This decrease in electricity generation occurred because the country experienced slightly cooler temperatures in September 2014 compared to September 2013, due to lower demand for residential cooling, as evident in the 2.1% year-over-year decrease in U.S. population-weighted cooling degree days. At the region-level, the Northeast, MidAtlantic, Southeast, Florida, and West, all saw slight increases in electricity generation compared to September 2013, while the Central region and Texas saw a decrease in electricity generation.

Compared to the previous September, the only regions that saw an increase in electricity generation from coal were Florida and the West, with each seeing only small increases compared to last year. The MidAtlantic and Central saw considerable drops in coal generation compared to September 2013, while the Southeast and Texas only saw a slight decrease in electricity generation from coal. Texas and Central region saw decreases in natural gas generation. All other regions saw an increase in electricity generation from natural gas, with the MidAtlantic and Southeast regions seeing the largest percentage increases in natural gas generation compared to the previous year.

Total electricity generation from nuclear in the U.S. was up 2.6% compared to the previous September. For the fourth consecutive month, the Central region had the largest percentage increase in nuclear generation compared to the previous year. This occurred because the Fort Calhoun nuclear plant was offline in September 2013 (and Fort Calhoun nuclear plant had been offline since May 2011 due to damage caused by severe flooding). In September 2014, Fort Calhoun nuclear plant was operating at full capacity.

Fossil fuel consumption by region





map showing electricity regions

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

The second tab compares natural gas consumption in September 2013 and September 2014 by region. This consumption pattern mirrored the change in electricity generation from natural gas, with the Central region having the largest percentage change in natural gas consumption for the third consecutive month.

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. The Central region was the only part of the country where coal showed a noticeable increase in the share of total fossil fuel consumption at the expense of natural gas. In the MidAtlantic and Southeast regions, natural gas increased its share of total fossil fuel consumption at the expense of coal, while in Florida, both coal and natural gas showed an increase in the share of total fossil fuel consumption at the expense of other fossil fuels.

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

Fossil fuel prices




To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $ / MMBtu basis as shown in the chart above. The price of natural gas at Henry Hub increased slightly from the previous month, going from $4.01 / MMBtu in August 2014 to $4.04 / MMBtu in September 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased for the eight consecutive month, going from $2.50 / MMBtu in August 2014 to $2.30 / MMBtu in September 2014. Like many natural gas prices in the Northeast, the New York City natural gas price is now well 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 second consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $16.89 / MMBtu in August 2014 to $16.34 / MMBtu in September 2014. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.

A fuel price comparison based on equivalent energy content ($ / MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. The spread between the Henry Hub natural gas price and the price of Central Appalachian coal on a $ / MWh basis increased only slightly compared to last month. However, because of the continued decrease in the New York City natural gas price, the price of Central Appalachian coal on a $ / MWh basis continues to be higher than the New York City natural gas price.

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

 

Regional Wholesale Markets: September 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

In September, wholesale electricity and natural gas prices traded in a narrow band near the bottom of the twelve-month range. The highest electricity prices in the country for the month approached $68/MWh in both the Mid-Atlantic (PJM) and Northern CA (CAISO). The lowest electricity prices were found in the Midwest (MISO), at $27/MWh. New York City (NYISO) prices bottomed out at $30.95/MWh, setting a new twelve-month low for the region. In natural gas markets, the highest price in the country was $4.58/MMBtu in Northern CA (PG&E Citygate) and the lowest price was $1.62/MMBtu in the Mid-Atlantic (Tetco M-3). New twelve-month low prices were set in both the Mid-Atlantic and New York City (Transco Z6 NY).

Though prices in all regions tended to trade towards the bottom of the yearly range in September, prices in the Northeast continued to exhibit behavior different from the rest of the country. Due to the regions' proximity to large Marcellus natural gas production and a pipeline infrastructure that is still trying to catch up with the rapid production increases, Northeast natural gas prices, and by extension, electricity prices, can be volatile. During periods of low energy demand, natural gas and electricity prices can be the lowest in the country as robust natural gas supplies enter the area. During periods of high demand, however, pipelines into the region quickly reach capacity and prices spike to the highest in the country. In September, the spread between the lowest and highest natural gas and electricity prices during the month was significantly higher in New England, New York City and the Mid-Atlantic than at any other point in the country. This spread will only increase in the coming months, as energy demand and prices will spike in the Northeast at the first hint of cold weather.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Daily peak electricity system demand levels ranged widely in September, with peak loads in many regions close to both the annual minimum and maximum levels within the month. New York State (NYISO) and California (CAISO) both set new annual peaks in September and New England (ISONE), Mid-Atlantic (PJM), Midwest (MISO), Texas (ERCOT) and Tucson Electric were all fairly close to their annual peak maximum demand levels. Though not unheard of, it is uncommon to have higher peak demand days in September than in August. New England, New York, Mid-Atlantic, California and Tucson Electric all had higher peaks this September than occurred in August. Most of these high demand days occurred before September 5th, when weather in much of the country is still very much summer-like. As the month progresses and the weather more resembles fall, peak demand levels can drop precipitously as temperatures fall. This is especially evident in New England, New York State, Mid-Atlantic and California, which were all within 10% of both the annual maximum and minimum levels in September.

 

Electric Power Sector Coal Stocks: September 2014

 



Total U.S. coal stocks increased by 3.1 million tons compared to the previous month. This increase in coal stocks follows the normal seasonal pattern where coal plants begin to build up coal stocks during the autumn months in preperation for increased coal consumption during the winter. However, total U.S. coal stocks are still relatively low compared to the past several years, and compared to the previous September, total U.S. coal stocks are down 18.4%. This large decrease in year-over-year stockpile levels is the result of increased coal-fired electricity generation during a long, cold winter across much of the U.S. and decreased coal deliveries due to lingering rail transportation issues. Certain coal-fired generators have been forced to receive coal by truck and lower or completely idle output due to rail delivery problems. Record grain harvests in 2013 and 2014 and increasing shipments of petroleum products are in some cases contending with coal deliveries and have strained rail capacity on certain lines.

Days of burn




The average number of days of burn held at electric power plants is a forward looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. The total bituminous supply increased from 67 days the previous month to 81 days in September 2014, while the total subbituminous supply increased from 41 days in August 2014 to 46 days in September 2014.

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

  September 2014   September 2013   August 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 6,819 88   6,031 62 13.1% 5,564 68 22.5%
  Subbituminous 553 133   473 82 17.1% 356 127 55.4%
South Bituminous 33,309 86   42,193 94 -21.1% 29,017 68 14.8%
  Subbituminous 6,324 69   5,633 61 12.3% 4,184 42 51.1%
Midwest Bituminous 13,142 69   14,251 69 -7.8% 12,782 61 2.8%
  Subbituminous 25,024 42   36,949 62 -32.3% 24,089 39 3.9%
West Bituminous 4,597 82   6,038 106 -23.9% 4,820 82 -4.6%
  Subbituminous 18,362 47   26,228 66 -30.0% 18,395 43 -0.2%
U.S. Total Bituminous 57,867 81   68,513 85 -15.5% 52,183 67 10.9%
  Subbituminous 50,263 46   69,282 63 -27.5% 47,025 41 6.9%

Source: U.S. Energy Information Administration

NOTE: Stockpile levels shown above reflect a sample of electric power sector plants, which were used to create the days of burn statistics. These levels will not equal total electric power sector stockpile levels.

 

Methodology and Documentation

General

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

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

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

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

Key Indicators

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

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

Sector Definitions

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

Degree Days

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

Per Capita Retail Sales

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

Composition of Fuel Categories

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

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

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

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

Relative Fossil Fuel Prices

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

Average Days of Burn

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

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

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

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

Coal Stocks vs. Days of Burn Stocks

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