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Electricity Monthly Update

With Data for October 2016  |  Release Date: Dec. 27, 2016  |  Next Release Date: Jan. 25, 2017

Previous Issues

Highlights: October 2016

  • Due to a mid-October heat wave, Texas (ERCOT) experienced the highest wholesale electricity prices in the country during the month, as prices reached $58/MWh on October 18.
  • Wholesale natural gas prices fell briefly to lows of $0.32/MMBtu in New York City and $0.39/MMBtu in the Mid-Atlantic.
  • Only the Northeast and Western regions saw noticeable declines in net generation compared to October 2015.

Key Indicators

  October 2016 % Change from October 2015
Total Net Generation
(Thousand MWh)
312,788 0.2%
Residential Retail Price
12.45 -2.1%
Retail Sales
(Thousand MWh)
291,985 -1.4%
Heating Degree-Days 168 -26.3%
Natural Gas Price, Henry Hub
3.01 27.3%
Natural Gas Consumption
775,514 -6.0%
Coal Consumption
(Thousand Tons)
54,638 1.8%
Coal Stocks
(Thousand Tons)
163,474 -6.9%
Nuclear Generation
(Thousand MWh)
60,733 0.3%

U.S. electric power industry is getting more beneficial use out of its combustion waste

The U.S. electric power industry's combustion byproducts (CBP) beneficial use rate has risen steadily since 2011, rising from 33% in 2011 to 40% in 2015. The CBP beneficial use rate represents the percentage of total CBP that goes to beneficial uses.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report

CBPs, such as fly ash, bottom ash, and gypsum from flue gas desulfurization (FGD) systems, are produced as a result of the combustion of coal, petroleum coke, residual fuel oil, and wood/wood waste. In the electric power industry, most CBPs are produced as a result of the burning of coal for electricity generation. Power producers report total CBP produced per year and the disposition of the CBP and provide that data to EIA.

CBP disposition includes disposal (onsite landfills, onsite ponds, and disposal offsite), beneficial use (sold, used onsite, and used offsite), and storage (onsite or offsite) for subsequent disposal or sale. Examples of the beneficial use of CBP include the use of CBP in the manufacture of products like concrete and wallboard.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report

Total CBP produced has fallen by almost 17% between 2011 (142.5 million tons) and 2015 (118.8 million tons). This is primarily a result of reduced coal-fired generation and coal consumption in the power industry. In 2011, coal had a 42% share of total power generation, and coal consumption was 934.9 million tons. In 2015, coal's share of power generation was 33%, and coal consumption fell to 739.6 million tons. The recent fall in coal consumption has been driven primarily by increased competition from natural gas and more stringent state and federal environmental regulations.

Against the backdrop of falling CBP production, beneficial use was the only component of CBP to increase. The beneficial use of CBP has increased from 46.9 million tons in 2011 to 47.9 million tons in 2015. CBP disposal fell from 86.9 million tons in 2011 to 67.4 million tons in 2015. CBP storage, meanwhile, decreased from 8.7 million tons in 2011 to 3.5 million tons in 2015.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report

CBPs are generally classified into three categories. Those categories include fly ash, bottom ash, and FGD byproducts. Collectively over the past five years, total CBP was composed of 49% fly ash, 32% FGD byproducts, 18% bottom ash, and a small 1% other category.

CBP is disposed of or used in different ways depending on the type of byproduct, the technology and processes at the power plant, and regulations the power plant has to follow. Averaged over 2011 to 2015, 39% of fly ash, 33% of bottom ash, 38% of FGD byproducts, and 93% of ash from integrated gasification combined cycle (IGCC) applications were put to beneficial use.

Principal Contributors:

Paul McArdle

Joy Liu


End Use: October 2016

Retail rates/prices and consumption

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

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

Average revenue per kWh by state

Average revenue per kilowatthour figures decreased in 19 states in October compared to last year. The largest declines were found in California (down 9.2%), Nevada (down 7.2%), and Hawaii (down 4.4%). Thirty states and the District of Columbia increased compared to last year, led by Alabama (up 9.7%), Delaware (up 8.7%), and West Virginia (up 7.7%).

Total average revenues per kilowatthour were down 1.6% to 10.15 cents in October compared to last year. All sectors were down on the month, from a 4.7% drop in the Transportation sector to a 2.1% drop in the Residential sector. Retail sales were down overall (1.4%) to 291,985 gigawatthours (GWh). The Commercial, Transportation, and Industrial sectors showed declines of 0.4%, 3.6%, and 6.4%, respectively, while the Residential sector showed a gain of 1.8%.

Retail sales

State retail sales volumes were down in 27 states in October compared to last year. Maine recorded the largest year-over-year decline, down 13.5%, California and Indiana had the next largest declines, down 12.9 and 7.2%, respectively. Twenty-three states and the District of Columbia had retail sales volume increases in October, led by the District of Columbia (up 13.2%), Tennessee (up 5.8%), and Mississippi (up 5.5%).

October 2016 was the 3rd warmest October on record according to the National Oceanic and Atmospheric Administration (NOAA). Heating Degree Days (HDD) were lower across most of the country, down in 38 states and the District of Columbia compared to last October. Twelve states had an over 50-percent-decrease in HDDs. The largest year-over-year decrease was found in Alabama, followed by Kentucky, Georgia, and Virginia. Eight states had more HDDs than last October, with all these states found in the Northwest. Oregon had the largest HDD increase of any state, followed by Idaho, Washington, Montana, and Alaska.


Resource Use: October 2016

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 by only 0.2% from the previous October. This occurred because the country, as a whole, experienced above average temperatures that were very similar to the above average temperatures experience last year. At the regional-level, only the Northeast and Western regions saw noticeable declines in net generation compared to October 2015.

The change in electricity generation from coal compared to the previous October was mixed throughout the country. The MidAtlantic, Southeast, and Texas all saw increases in coal generation from the previous year, with the largest percent increase occurring in the Texas (25.7%). Conversely, the Northeast, Central, Florida, and the West regions saw a decrease in coal generation, with the Northeast region seeing the largest percent decrease (-47.5%) in coal generation.

The change in natural gas generation was also mixed throughout the country, with the MidAtlantic, Central, and Florida all observing increases in natural gas generation compared to last year, while the Northeast, Southeast, Texas, and the West regions all saw decreases in natural gas generation. As a whole, nuclear generation was up slightly (0.3%) compared to the previous October, while renewables generation was up 17.0% compared to last year.

Fossil fuel consumption by region

map showing electricity regions

The chart above compares coal consumption in October 2015 and October 2016 by region and the second tab compares natural gas consumption by region. Changes in coal and natural gas consumption closely mirrored the change 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. In October 2016, the Southeast, Texas, and West regions saw increases in the share of coal consumption at the expense of natural gas consumption, while the Northeast, MidAtlantic, Central, and Florida all saw natural gas consumption increase at the expense of coal compared to the previous year.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were 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 average price of natural gas at Henry Hub decreased from the previous month, going from $3.05/MMBtu in September 2016 to $3.01/MMBtu in October 2016. The natural gas price for New York City (Transco Zone 6 NY) decreased from the previous month, going from $1.33/MMBtu in September 2016 to $1.23/MMBtu in October 2016.

The New York Harbor residual oil price increased from the previous month, going from $7.79/MMBtu in September 2016 to $8.41/MMBtu in October 2016. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.

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

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: October 2016

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

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

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

Wholesale prices

Selected wholesale electricity pricing locations

Wholesale electricity prices were lowest in New England (ISONE) during the month, dipping to $16/MWh on October 10 and also setting a new low for the last 12 months at the hub. This was the result of both low natural gas prices and low electricity demand in New England. Prices were also very low in New York City (NYISO), nearly setting a new 12-month low by dropping to $20/MWh on October 12 during a time of lower electricity demand and natural gas prices in the area at just over $1/MMBtu during that week. The highest priced hub during the month was Texas (ERCOT), which reached $58/MWh on October 18. During the week of the 18th, electricity demand was very high for late October in Texas, nearly reaching 58 gigawatts (GW) on both October 17 and 18 and natural gas prices were over $3/MMBtu at the Houston Ship Channel during the week. Wholesale electricity prices in Louisiana (into Entergy) nearly set a new 12-month high at $48/MWh on October 18th, dealing with the same weather and natural gas factors affecting Texas (ERCOT) at that time.

Wholesale natural gas prices were bifurcated by region during October, with extremely low prices in the Northeast and prices at or near 12-month highs in the rest of the country. New 12-month lows were set in New York City at Transco Z6 NY, which dropped all the way to $0.32//MMBtu and in the Mid-Atlantic at Tetco M-3, which fell to $0.39/MMBtu. Prices were below $1/MMBtu in New York City on four days during the month and for 12 days during the month in the Mid-Atlantic (Tetco M-3). Across the rest of the country, however, 12-month high prices were set in the Midwest (Chicago Citygates), Louisiana (Henry Hub), and Texas (Houston Ship Channel), and not far from 12-month highs at all other pricing locations.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Electricity system daily peak demand remained on the lower end of the 12-month range at all hubs except Texas (ERCOT) during October. A new 12-month low was set in New York State (NYISO) and Progress Florida came within a whisker of a new 12-month low. New England (ISONE), the Mid-Atlantic (PJM), the Midwest (MISO), Southern Company, and Bonneville Power Administration were also not far off 12-month low daily peak demand levels. The one exception was Texas (ERCOT), which experienced one of its hottest and driest Octobers on record. Daily peak demand levels reached 58 GW on October 17 and 18 as a late-season heat wave hit the region. Temperatures reached the high-80's and low 90's across Texas from October 15-20, even hitting 100 in McAllen, Texas on four days straight from October 17-20.


Electric Power Sector Coal Stocks: October 2016


In October, U.S. coal stockpiles increased to 164 million tons, up 3.4% from the previous month. This increase in total coal stockpiles follows the normal seasonal pattern whereby coal stockpiles begin to build-up during the autumn months.

Days of burn

The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn decreased from 92 days of burn in September to 86 days of forward-looking days of burn in October. For subbituminous units largely located in the western United States, the average number of days of burn remained unchanged at 87 days in October.

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

  October 2016   October 2015   September 2016  
Zone Coal Stocks (1000 tons) Days of Burn   Stocks (1000 tons) Days of Burn % Change of Stocks Stocks (1000 tons) Days of Burn % Change of Stocks
Northeast Bituminous 5,646 84   7,509 95 -24.8% 5,487 95 2.9%
  Subbituminous 136 69   731 174 -81.4% 136 97 0.0%
South Bituminous 27,996 83   34,879 89 -19.7% 27,339 88 2.4%
  Subbituminous 6,039 73   6,946 76 -13.1% 5,631 68 7.2%
Midwest Bituminous 16,909 94   16,311 82 3.7% 16,549 99 2.2%
  Subbituminous 43,096 84   41,629 71 3.5% 40,862 84 5.5%
West Bituminous 5,859 84   5,628 75 4.1% 5,885 84 -0.5%
  Subbituminous 31,312 95   34,905 94 -10.3% 30,830 95 1.6%
U.S. Total Bituminous 56,410 86   64,328 87 -12.3% 55,260 92 2.1%
  Subbituminous 80,583 87   84,211 80 -4.3% 77,459 87 4.0%

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 are proprietary and non-public.

Key Indicators

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

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

Sector Definitions

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

Degree Days

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

Per Capita Retail Sales

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

Composition of Fuel Categories

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

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

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

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

Relative Fossil Fuel Prices

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

Average Days of Burn

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

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

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

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

Coal Stocks vs. Days of Burn Stocks

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