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Electricity Monthly Update

With Data for January 2017  |  Release Date: March 24, 2017  |  Next Release Date: April 25, 2017

Previous Issues

Highlights: January 2017

  • Wholesale natural gas prices in the Northwest (Sumas) were the highest since March 2014.
  • Bonneville Power Administration's electricity system peak demand reached its highest level in nearly four years on January 6.
  • Hydroelectric generation in the West increased 40% compared to the previous year due to increased precipitation that occurred late in 2016.

Key Indicators

  January 2017 % Change from January 2016
Total Net Generation
(Thousand MWh)
344,973 -2.2%
Residential Retail Price
12.22 2.0%
Retail Sales
(Thousand MWh)
314,483 -0.9%
Heating Degree-Days 766 -12.0%
Natural Gas Price, Henry Hub
3.40 44.9%
Natural Gas Consumption
676,592 -15.8%
Coal Consumption
(Thousand Tons)
63,540 2.4%
Coal Stocks
(Thousand Tons)
157,412 -16.0%
Nuclear Generation
(Thousand MWh)
73,121 0.8%

EIA hourly electricity demand data shows impact of Hurricane Matthew

EIA collects and publishes hourly electricity system operating data, including actual and forecast demand. The U.S. Electric System Operating Data tool includes data from all 66 electric system balancing authorities in the United States. This tool can be used to track the impact that hurricanes and other significant electricity service disruptions have on electric system demand.

Electric customers from Florida to Virginia lost electric service due to Hurricane Matthew in early October 2016. Matthew, a Category 3 hurricane, first made landfall on the east coast of Florida on October 6. The hurricane moved north on a track through the Carolinas, where customer outages reached their peak on October 9, 2016. As a result of Hurricane Matthew, one million people were without power in Florida, around 600,000 in South Carolina, and 680,000 customers in North Carolina.

One way to see the storm's impact is on the Grid Overview page. Select Florida's regional daily demand data for the day after landfall (October 7) and compare these data to demand data from the same day the week before. The graph shows the impact on demand for Florida on October 7 in comparison to demand for the same region a week before.

Source: U.S. Energy Information Administration, Form EIA-930, Hourly and Daily Balancing Authority Operations Report

Similarly, the demand data can show and track recovery periods, both regionally and for individual balancing authorities, either comparing actual demand during and after the hurricane to actual demand during a comparable prior period or by comparing actual demand to forecast demand data. The charts below compares hourly balancing authority data for actual demand, forecast demand, and the prior week's actual demand.

Beginning with demand charts for two balancing authorities in Florida, the chart below shows reduced demand in New Smyrna Beach on October 6. On October 7, all electric supply was lost in the middle of the day. Electric service was not fully restored until October 9.

Source: U.S. Energy Information Administration, Form EIA-930, Hourly and Daily Balancing Authority Operations Report

On October 5, parts of Jacksonville were evacuated in anticipation of the storm and actual demand was lower than forecast. The storm lowered demand by more than half. Demand did not recover until October 12. The prior week's higher demand is partially due to hotter temperatures observed in the region.

Source: U.S. Energy Information Administration, Form EIA-930, Hourly and Daily Balancing Authority Operations Report

Hurricane Matthew made landfall in South Carolina around 3 a.m. on October 8. The chart below shows actual demand, forecast demand, and the prior week's actual demand for the South Carolina Public Service Authority. Actual demand on October 8 and 9 was 67,000 megawatthours, while forecasted demand was 105,000 megawatthours, a 35% difference. Recovery can be tracked to October 12, when actual demand and forecast demand align.

Source: U.S. Energy Information Administration, Form EIA-930, Hourly and Daily Balancing Authority Operations Report

In 2016, EIA began collecting and publishing hourly electricity operating data, including actual and forecast demand, net generation, and electricity interchange between electric systems. The information is collected directly from each interconnected electric system on the EIA-930 information collection form, the first hourly data collection conducted by a federal statistical agency. This new data collection expands the availability of system operating data to the entire Lower 48 states and makes it available in a consistent format from one source.

Principal Contributor:

Sara Hoff


End Use: January 2017

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 11 states in January compared to last year. The largest declines were found in Louisiana (down 11.7%), Delaware, and Ohio (each down 3%). Thirty-nine states and the District of Columbia increased compared to last year, led by Oklahoma (up 12%), Indiana (up almost 10%), and Alaska (up 8.4%).

Total average revenues per kilowatthour were up 1.9% to 10.15 cents in January compared to last year. Three sectors were up on the month, the Industrial sector with a 2.7% rise, the Residential sector with a 2% rise, and the Commercial sector with a 1.7% rise. Retail sales were down in the Residential, Commercial and Industrial sectors by 1.4%, 0.6, and 0.4, respectively. The Transportation sector showed a slight increase in retail sales from last year, growing by 0.9%.

Retail sales

State retail sales volumes were down in 28 states and the District of Columbia in January compared to last year. West Virginia recorded the largest year-over-year decline, down 11.2%, Virginia and South Carolina had the next largest declines, down 7.8% and 7.3%, respectively. Twenty-two states had retail sales volume increases in January, led by Idaho (up 11.8%), Oregon (up 10.6%), and Montana (up 10%).

Heating Degree Days (HDD) were lower across most of the country, down in 37 states and the District of Columbia compared to last January. Twelve states, all in the West and Rocky Mountain regions had an increase in HDDs. The largest year-over-year increases were found in Alaska, Idaho, Montana, Washington, and Oregon. All these states had an increase of more than 20% in HDDs from a year ago.


Resource Use: January 2017

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 January 2017, net generation in the United States decreased 2.2% from the previous January. The country, as a whole, experienced significantly above average temperatures in January 2017. This led to a decreased need for residential heating and thus, a decrease in electricity generation compared to last January, when temperatures were much closer to average across the country. At the regional-level, only the West saw a noticeable increase (6.8%) in net generation compared to the previous year.

The change in electricity generation from coal was mixed throughout the country, with Florida, Texas, the Central, and Western regions all observing increases in coal generation, while the Northeast, MidAtlantic, and Southeast all saw decreases in electricity generation from coal. Natural gas generation decreased in all parts of the country compared to January 2016, with Texas seeing the largest percent decrease (-23.6%) compared to the previous January.

As a whole, nuclear generation was up 0.8% compared to January 2016, with Texas seeing the largest percent increase (3.4%) from the previous year. Hydroelectric generation was down across the country compared to the previous January, except for in the Western region, where increased precipitation led to a 40% rise in hydroelectric generation.

Fossil fuel consumption by region

map showing electricity regions

The chart above compares coal consumption in January 2016 and January 2017 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption closely mirrored their respective changes in coal and 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 January 2017, all regions of the country, except for the Northeast, saw an increase in the share of coal consumption at the expense of natural gas consumption.

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 $3.70/MMBtu in December 2016 to $3.40/MMBtu in January 2017. The natural gas price for New York City (Transco Zone 6 NY) also decreased from the previous month, going from $4.53/MMBtu in December 2016 to $3.94/MMBtu in January 2017.

The New York Harbor residual oil price saw an increase from the previous month, going from $9.12/MMBtu in December 2016 to $9.70/MMBtu in January 2017. 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 price of natural gas at Henry Hub was still above the price of Central Appalachian coal on a $/MWh basis in January 2017, despite the decrease in the price of Henry Hub natural gas from the previous month. The price of natural gas at New York City on a $/MWh basis was above the price of Central Appalachian coal for a second consecutive month, despite the gap between the two prices decreasing, mainly due to a decrease in 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: January 2017

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 natural gas and electricity prices varied widely by trading hub in January. The highest prices were found in the Northeast, which is typical in this pipeline-constrained region during the winter. Both electricity and natural gas prices peaked on Monday, January 9, the last of a days-long cold snap. Temperatures on this day reached only 19 degrees in Boston and 23 degrees in New York City, far below averages.

This cold weather led to electricity prices of $96/MWh in New York City (NYISO) and $81/MWh in New England (ISONE) and natural gas prices of $7.90/MMBtu in New York City (Transco Z6 NY) and $10.05/MMBtu in New England (Algonquin). Prices at these hubs dropped precipitously the next day, January 10, as temperatures increased 20+ degrees and demand moderated.

The next highest electricity and natural gas prices were found in the Northwest, a somewhat rare occurrence as plentiful hydropower and moderate temperatures often lead to lower prices in the region when compared to the rest of the country. This month, however, the weather was much colder-than-normal in Washington, Oregano, and Idaho for the second straight month. Natural gas prices at Sumas reached $5.46/MMBtu on January 3 with electricity prices hitting $62/MMBtu at the Mid-C trading hub. This is the highest natural gas price recorded at Sumas since March 5, 2014.

Wholesale natural gas prices across the rest of the country (outside of the Northeast and Northwest) remained in the $3-$4/MMBtu range most of the month, though this is on the upper end of each hub's 12-month range. Wholesale electricity prices across the rest of the country remained roughly in the middle of each hub's respective 12-month range.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Electricity system daily peak demand was somewhat muted across most electricity systems in January as the eastern two-thirds of the country experienced extremely mild weather compared to historical averages. The one outlier was the Northwest, which experienced its second month in a row of much-colder-than-normal temperatures. As such, Bonneville Power Administration daily peak demand was very high on many occasions. On January 6, BPA daily peak demand hit 10,943 MW, its highest daily peak demand since March 25, 2012 (11,713 MW). BPA peak demand also exceeded 10,000 MW on six days in January (January 4-6 and January 12-15), equal to the total number of days where demand exceeded 10,000 MW over the past four years combined (2013-2016). In all other electricity systems, daily peak demand fell far short of the top end of their 12-month range and even approached the low end of the 12-month range on individual days during the month.


Electric Power Sector Coal Stocks: January 2017


In January, U.S. coal stockpiles decreased to 157 million tons, down 4% from the previous month. This decrease in total coal stockpiles follows the normal seasonal pattern whereby coal stockpiles are drawn down during the winter 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 increased from 80 days of burn in December to 90 days of forward-looking days of burn in January. For subbituminous units largely located in the western United States, the average number of days of burn increased from 90 days in December to 99 days in January.

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

  January 2017   January 2016   December 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 5,181 75   7,967 100 -35.0% 5,484 66 -5.5%
  Subbituminous 96 30   652 220 -85.3% 98 36 -2.4%
South Bituminous 29,594 90   35,366 97 -16.3% 29,868 77 -0.9%
  Subbituminous 5,760 76   7,792 98 -26.1% 5,978 68 -3.6%
Midwest Bituminous 15,035 91   17,447 92 -13.8% 16,279 87 -7.6%
  Subbituminous 41,909 96   46,617 87 -10.1% 44,048 87 -4.9%
West Bituminous 5,583 103   4,912 79 13.7% 5,868 98 -4.9%
  Subbituminous 29,650 107   40,971 121 -27.6% 31,244 100 -5.1%
U.S. Total Bituminous 55,394 90   65,692 94 -15.7% 57,499 80 -3.7%
  Subbituminous 77,415 99   96,032 101 -19.4% 81,369 90 -4.9%

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


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.