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Electricity Monthly Update

With Data for November 2019  |  Release Date: Jan. 27, 2020  |  Next Release Date: Feb. 26, 2020

Previous Issues

Highlights: November 2019

  • The spread between the New York City natural gas price and Central Appalachian coal price decreased considerably compared to last month, mainly due to the increase in the New York City natural gas price.
  • Southern Company recorded a 12-month low electricity peak demand day on November 29.
  • Net electricity generation in the United States decreased 1.7% in November 2019 compared to the previous year, mainly due to this November being warmer than November 2018.

Key indicators

Statewide average temperature ranks
Statewide precipitation ranks
Total net generation
Net generation by select fuel sources

Major coal-generating unit retirements in 2019 continue decade long trend towards reduced coal capacity

During the past decade, the United States has seen significant coal retirements, and 2019 continued that trend with 12,529 megawatts (MW) of coal summer capacity retired. This level of retirements is the third-highest level of annual coal retirements since 2010 after 2015 (14,866 MW) and 2018 (13,304 MW). In 2018 and 2019, decreasing wholesale prices, low natural gas prices, and increased participation of renewable energy resources all contributed to coal retirements. In addition to these factors, in 2015, environmental compliance with the Mercury and Air Toxic Standards (MATS) for coal-fired and oil-fired power plants was a significant factor in determining coal retirements.

U.S. utility-scale coal generating unit retirements Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report and Form EIA-860M, Monthly Update to the Annual Electric Generator Report.

Notes: Data for 2010 through 2018 are final; data for 2019 are preliminary. Megawatts represent summer capacity of generating units.

Coal retirements in 2019 were not limited to any one state or type of coal. The three largest coal plants to retire in 2019 were First Energy Bruce Mansfield (2,490 MW) in Pennsylvania, Navajo (2,250 MW) in Arizona, and Gorgas (1,063 MW) in Alabama. On a state-wide basis, the states with the largest coal capacity retirements were:

1. Pennsylvania (2,589 MW, or 20% of total coal retirements)
2. Arizona (2,250 MW, or 18%)
3. Illinois (2,002 MW, or 16%)
4. Alabama (1,063 MW, or 8%)
5. Georgia (982 MW, or 8%)

Broken down by primary coal rank, bituminous coal (9,276 MW) saw the largest drop in capacity, followed by subbituminous coal (3,166 MW).

U.S. utility-scale coal operating nameplate capacity Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report and Form EIA-860M, Monthly Update to the Annual Electric Generator Report.

Note: Data for 2019 are preliminary.

The increase in coal-unit retirements since 2010 has significantly reduced coal-unit capacity. During the past decade, U.S. total coal summer capacity dropped from 314,555 MW in 2010 to 226,786 MW in 2019, a 28% reduction in summer capacity. Annually, coal-unit capacity has declined by an average of 3.5%. About 89% of the change in coal-unit capacity between 2010 and 2019 (87,769 MW) can be attributed to coal-unit retirements (78,447 MW) occurring in 2011 through 2019. The remaining 11% reduction (9,322 MW) is from the net effect of the fuel switching of coal units to other fuels (primarily natural gas) (an 18,458 MW reduction). It is also a result of capacity additions from new coal units coming online (mostly in 2011 and 2012) (a 9,136 MW addition). The 2019 5.5% year-over-year decrease in coal capacity (239,962 MW to 226,783 MW) is, on a percentage basis, the third-largest this decade. The largest year-over-year declines of the decade were in 2015 at 6.2% and in 2018 at 6.0%.

U.S. utility-scale operating coal capacity Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report and Form EIA-860M, Monthly Update to the Annual Electric Generator Report.

Note: Data for 2010 through 2018 are final; data for 2019 are preliminary. Megawatts represent summer capacity of generating units.

According to the U.S. Energy Information Administration’s (EIA) latest inventory of electric generators, retirements of coal units are expected to continue into the 2020s. In the first half of the decade (2020–2024), 15,663 MW of coal capacity has reported plans to retire. Currently, 2020 has the highest total of planned retirements (6,102 MW), followed by 2022 (3,713 MW). Planned retirements are expected in all parts of the country. The states with the largest planned retirements are Michigan (2,606 MW), Ohio (1,500 MW), Kentucky (1,371 MW), North Carolina (960 MW) and Tennessee (870 MW). The plants with the largest planned capacity retirements are St. Clair in Michigan (1,065 MW in May 2022), Paradise in Kentucky (971 MW in January 2020), and Bull Run in Tennessee (870 MW in December 2023). Broken down by primary coal rank, subbituminous coal has the most planned retirements with 8,274 MW, followed by bituminous coal (7,122 MW), lignite (157 MW) and waste coal (110 MW).

U.S. utility-scale planned coal capacity Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report and Form EIA-860M, Monthly Update to the Annual Electric Generator Report.

Note: All data are preliminary. Megawatts represent summer capacity of generating units.

New England net electricity inflows and net generation by energy source Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report and Form EIA-860M, Monthly Update to the Annual Electric Generator Report.

Note: All data are preliminary.


Principal Contributor:

Alex Gorski
(Alexander.Gorski@eia.gov)

 

End Use: November 2019


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 22 states and the District of Columbia in November compared to last year. The largest declines were found in Hawaii (down over 9%), Ohio (down over 6%), and Rhode Island (down almost 5%). Twenty seven states increased revenue per kilowatthour compared to last year, led by Maine (up over 10%), Alaska (up over 8%), and Vermont (up almost 7%). One state, Tennessee, had no change from a year ago.


Total average revenues per kilowatthour (kWh) in November 2019 were up by 0.8% from November 2018, to 10.43 cents/kWh. The Residential and Commercial sectors both rose slightly, up by 1.1% and 0.3%, respectively. The Industrial and Transportation sectors were down by 1.8% and 1.4%, respectively. Total retail sales were down by 3.4% from November 2018. All sectors except Transportation fell from a year ago. The Industrial sector fell the most, dropping by 6.6%. The Commercial sector followed, falling by 2.6%. The Residential sectors decreased by 1.7%. The Transportation sector rose slightly, up by 0.3%.

Retail sales



State retail sales volumes were down in 44 states and the District of Columbia in November compared to last year. Maine had the largest year-over-year decline, down over 24%. The District of Columbia followed in second place, dropping almost 10%. California, Missouri, and Indiana followed, each with a fall of almost 8%. Only six states had retail sales volume increases in November, led by New Mexico (up almost 6%), West Virginia (up almost 5%), and Hawaii (up almost 3%).


Heating Degree Days (CDD) were down in 27 states compared to last November. The greatest percentage drop in HDDs occurred in Arizona, which was down 29%. Texas, Alaska, Missouri, and Utah all had HDD drops of over 10%. Twenty-two states and the District of Columbia had an increase in HDDs in November. Washington had the greatest increase in HDDs, up over 10%. California followed, with a 10% increases in HDDs.

 

Resource Use: November 2019

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 electricity generation in the United States decreased 1.7% in November 2019 compared to the previous year. This decrease in electricity generation was primarily driven by cooler temperatures last November, which led to a greater need for residential customer heating and thus increased electricity generation in November 2018 compared to this November. At the regional-level, the change in electricity generation compared to the previous November was mixed, with the Northeast, MidAtlantic, Central, Southeast, and Florida all seeing a year-over-year decrease in electricity generation, while the West and Texas all saw an increase in electricity generation.

Electricity generation from coal decreased in all parts of the country compared to the previous year. All regions of the country, except for the Northeast and Florida, saw an increase in natural gas generation compared to November 2018. Nuclear generation as a whole was relatively flat year-over-year, only increasing by 0.3% compared to the previous year.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in November 2018 and November 2019 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption were similar to 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. All regions of the country, except for Florida, saw their shares of natural gas increase at the expense of coal. Florida saw a very slight increase in other fossil fuels consumption, which caused a slight decrease in the relative market share of natural gas.

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 increased from the previous month, going from $2.38/MMBtu in October 2019 to $2.72/MMBtu in November 2019. After three consecutive month-over-month price decreases, the natural gas price for New York City (Transco Zone 6 NY) increased compared to the previous month, going from $1.60/MMBtu in October 2019 to $2.74/MMBtu in November 2019. The average price of Central Appalachian coal remained relatively unchanged from the previous month, only dropping from $2.80/MMBtu in October 2019 to $2.78/MMBtu in November 2019.

The New York Harbor residual oil price saw a decrease from the previous month, going from $12.96/MMBtu in October 2019 to $12.66/MMBtu in November 2019. As is the case most months, oil is used primarily for peaking operations and is largely priced out of the market for baseload operations.

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 ($21.80/MWh) was below the price of Central Appalachian coal ($30.04/MWh) on a $/MWh basis, with the spread between the two decreasing compared to the previous month, mainly due to the increase in the Henry Hub natural gas price. The price of natural gas at New York City ($21.98/MWh) was below the price of Central Appalachian coal ($30.04/MWh) during November 2019, with the spread between the two prices decreasing considerably, mainly due to the increase in the New York City natural gas price compared to the previous 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: November 2019

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 very uniform across the country during November. The lowest price during the month at each hub ranged from $21-$35/MWh while the highest price at each hub ranged from $36-$62/MWh. No 12-month highs or lows were set, though prices in New England (ISONE), New York City (NYISO), the Mid-Atlantic (PJM), and the Midwest (MISO) were all within roughly $2/MWh of 12-month lows. Wholesale natural gas prices at the Henry Hub in Louisiana, historically the proxy pricing point for the U.S., ranged between $2.39-$2.87/MMBtu in November, up slightly from a $2.08-$2.71/MMBtu range last month. No 12-month high or low prices were set during the month at any selected location. The lowest natural gas price during the month was $1.21/MMBtu in the Southwest (El Paso San Juan). The highest price was $6.30/MMBtu in New England (Algonquin).

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system peak demand levels in November were lower than last month in eight of ten selected regions. Only New England (ISONE) and Bonneville Power Administration recorded higher peak demand days this month compared to October. A new 12-month low peak demand day was recorded in Southern Company, which reached only 22,012 MW on November 29. Also on the 29th, Progress Florida nearly recorded a new 12-month low with a peak of 5,513 MW, just above its 12-month low peak day of 5,305 MW. Energy demand, and prices, often increases significantly next month in December as winter conditions arrive to many parts of the country.

 

Electric Power Sector Coal Stocks: November 2019



Total U.S. coal stockpiles had a month-over-month increase of 4.2%, reaching 124 million tons in November 2019. This October to November rise in total U.S. coal stockpiles follows the normal seasonal pattern where coal stockpiles are built up during the fall months for use 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 the previous month, going from 99 days of forward-looking days of burn in October 2019 to 109 days of burn in November 2019. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 81 days of burn in October 2019 to 83 days of burn in November 2019.

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

  November 2019   November 2018   October 2019  
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 4,018 201   3,307 105 21.5% 3,996 193 0.6%
  Subbituminous 162 144   146 102 10.9% 162 158 0.0%
South Bituminous 22,797 112   19,193 77 18.8% 22,467 106 1.5%
  Subbituminous 5,709 67   4,613 53 23.8% 5,236 64 9.0%
Midwest Bituminous 11,527 86   8,782 66 31.3% 11,138 85 3.5%
  Subbituminous 25,709 99   28,005 95 -8.2% 25,039 97 2.7%
West Bituminous 3,184 116   3,915 83 -18.7% 3,223 66 -1.2%
  Subbituminous 22,412 72   19,293 69 16.2% 21,285 71 5.3%
U.S. Total Bituminous 41,526 109   35,197 76 18.0% 40,823 99 1.7%
  Subbituminous 53,991 83   52,057 79 3.7% 51,721 81 4.4%

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 are proprietary and non-public.

For a guide that describes electricity data that EIA collects and how the data are made available to the public, see the Guide to EIA Electric Power Data.

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 combustion 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.