Average monthly electric bills for residential customers in the United States were 1.8% lower in 2019 than in 2018. They declined by more than two dollars from $117.65 per month in 2018 to $115.49 per month in 2019. Since 2009, nominal average U.S. monthly electric bills have fluctuated within a narrow band from $105/month (2009) to $118/month (2018) with an average annual growth rate of 1%.
The U.S. Energy Information Administration (EIA) calculates average monthly bills by dividing total annual U.S. residential revenues by the number of customer accounts and by 12 (the number of months in the year). Generally, declines in the residential average monthly bill have been driven by reductions in average consumption per customer rather than decreases in average price, as was the case in 2019. Although the average U.S. residential price rose from 12.87 cents per kilowatthour (kWh) in 2018 to 13.01 cents/kWh in 2019, declines in average monthly consumption per customer from 914 kWh in 2018 to 887 kWh produced an overall reduction in average bills.
The reduction in average consumption per residential customers could be, in part, a result of cooler summer weather in 2019 relative to 2018. Heating degree days (HDDs) were up by 0.6% in 2019 compared with 2018, which would tend to increase consumption. However, cooling degree days (CDDs) were down by 5.3% in 2019, which pushed consumption down and more than offset the modest increase in HDDs. In addition, longer-term trends in energy efficiency have tended to push down average consumption over time. These trends in energy efficiency include increased use of behind-the-meter generation, high-efficiency appliances, LED (light-emitting diode) lights, and smart energy-saving devices (such as software programs for home automation systems). Since 2009, average monthly consumption per customer has fallen by 2.3% (908 kWh in 2009 versus 877 kWh in 2019).
In 2019, at the state level, 12 states saw increases in their average monthly residential electricity bills. The highest percentage increase in 2019 was in Maine (4.7%). Although average consumption in Maine was down slightly, average bills increased even more because of upticks in residential rates as a result of increases in 2019 prices for standard offer supply service set by the Maine Public Utilities Commission. The second-highest increase in average bills was in Montana (2.4%). This increase was a result, in part, of slight increases in average consumption and interim rate increases approved by the Montana Public Service Commission in March 2019 (see docket 2018.02.012, final order 7604u, December 20, 2019). Six states experienced less than 2% increases in their average monthly residential electricity bills: Texas (1.9%), Wyoming (1.7%), Alaska (1.4%), Oregon (1.4%), Washington (1.2%), and Florida (1.2%). The remaining four states had less than a 1% increase in their average monthly residential electricity bills: Georgia (0.6%), Rhode Island (0.5%), South Carolina (0.4%), and Hawaii (0.05%).
In contrast, 38 states and the District of Columbia experienced a decrease in their average monthly residential electricity bills in 2019. The four states with the largest declines in average bills all had decreases in excess of 5%. Kansas had the largest percentage drop in its average monthly bill, down 9.2%, followed by New York (7.4%), Missouri (7.1%), and Ohio (5.8%). The remaining 34 states and the District of Columbia all had reductions that were less than 5%.
|Source: U.S. Energy Information Administration, Form EIA-861, Annual Electric Power Industry Report|
The top five states with the highest average residential electricity bills in 2019 also ranked at the top in 2018. Hawaii, at $168.21, once again had has the highest state average monthly bill in 2019. Hawaii’s bills are at the top of this list mainly because electricity rates are almost three times the national average in Hawaii because of the state’s reliance on higher-cost, oil-fired generation that depends on marine imports of petroleum. Connecticut, with the second-highest bill ($150.71), had fairly modest average consumption levels (689 kWh), but its higher-than-average rates (21.87 cents/kWh) pushed it to the second position. The higher electricity rates in Connecticut are typical of the Northeast region, where the six New England states and New York are all in the top 10 for highest residential electricity rates. Rates tend to be higher in this region because of constraints on natural gas pipeline capacity during peak demand periods, the region’s significant distance from natural gas basins and storage locations, and a generally higher cost-of-living in this region. The remaining states in the top five (Alabama [$150.45], South Carolina [$144.73], and Mississippi [$135.87]) are similar in that they share geography, have slightly lower-than-average rates, and have high consumption levels because of significant summer cooling demand.
|Source: U.S. Energy Information Administration, Form EIA-861, Annual Electric Power Industry Report|
The five states with the lowest monthly average residential electricity bills in 2019 were Utah ($75.63), New Mexico ($80.04), Colorado ($83.07), Illinois ($92.37), and Idaho ($93.83). All (except Idaho) have both lower-than-average consumption levels and lower-than-average electricity rates. Idaho, meanwhile, has lower-than-average rates that more than compensate for its slightly higher-than-average consumption levels as a result of its significantly lower-cost hydroelectric generation capacity.
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 kilowatthour figures decreased in twenty-one states and the District of Columbia in September compared to last year. The largest decline was found in Missouri, down by almost 6%. Twenty-eight states increased revenue per kilowatthour compared to last year, led by New Mexico (up over 13%). One state, Kentucky, had no change from last September.
|Average Revenues/Sales (¢/kWh)||Retail Sales (thousand MWh)|
|End-use sector||September 2020||Change fromSeptember 2019||September 2020||Change fromSeptember 2019||Year to Date|
|Source: U.S. Energy Information Administration|
Total average revenues per kilowatthour (kWh) rose by 2.3% in September to 11.07 cents/kWh. The Transportation sector rose the most from last September, up by 6.4%. The Residential and Commercial sectors followed, each up by 3.0% and 1.0%, respectively. The Industrial sector fell slightly, down by 0.7%. Total retail sales were down by 6.7% from September 2019. All of the four sectors showed a drop in retail sales from a year ago. The Transportation sector dropped the most, down by 27%. The Industrial and Commercial sectors fell 10% and 8.1%, respectively. The Residential sector dropped the least amount of the four sectors, down by 3%.
State retail sales volumes were down in thirty-nine states and the District of Columbia in September compared to last year. The District of Columbia had the largest year-over-year decline, down almost 16%. Oklahoma and Wyoming followed, dropping by almost 15% and 14%, respectively. Eleven states had retail sales volume increases in September, led by Maine, up by almost 7%.
Cooling Degree Days (CDD) were down in thirty-five states and the District of Columbia compared to last September. The greatest percentage drop in CDDs occurred in Wisconsin, which was down 84%. Five states had over-60-percent drops in CDDs: Missouri (down almost 68%), Michigan (down almost 68%), Kansas (down over 65%), Illinois (down 63%), and Oklahoma (down 60%). Fourteen states had an increase in CDDs in September. Maine had the largest percent increase in CDDs, up over 500% from September 2019. Vermont, New Hampshire, and Oregon followed, all with percent increases of over 100%.
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.
Net electricity generation in the United States decreased 7.3% in September 2020 compared to the previous year. This decrease in electricity generation occurred because the country experienced a much cooler September in 2020 relative to September 2019. Cooling degree days (CDDs) were down 24.5% in September 2020 compared to September 2019, which was the second hottest September on record. This led to a decrease in the need for residential customer cooling for the country during this September compared to the previous September, which decreased the need for electricity generation compared to a year ago. At the regional-level, all regions of the country, except for the Northeast, saw a decrease in electricity generation compared to September 2019. The Northeast was the outlier and saw a 3.3% increase in electricity generation compared to the previous year, mainly due to experiencing warmer regional temperatures this September compared to last year.
Electricity generation from coal decreased from the previous September in all parts of the country, except for Florida. All parts of the country, except for the Northeast and West, saw natural gas generation increase compared to the previous year. Nuclear generation, as a whole, was down slightly by 0.5% compared to a year ago. All regions, except for the West, saw an increase in hydroelectric generation compared to September 2019. The Western region saw a 3.8% decrease in hydroelectric generation, which is only notable this time of year because the West experienced severe drought conditions in September and for most of this summer.
The chart above compares coal consumption in September 2019 and September 2020 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. The MidAtlantic, Central, Southeast, and Western regions all saw their share of coal increase at the expense of natural gas, while Florida and Texas all saw their share of natural gas increase at the expense of coal.
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.
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 saw a significant month-over-month decrease, going from $2.28/MMBtu in August 2020 to $1.93/MMBtu in September 2020. The natural gas price for New York City (Transco Zone 6 NY) also saw a sizeable month-over-month decrease, going from $1.51/MMBtu in August 2020 to $1.35/MMBtu in September 2020. The average price of Central Appalachian coal increased from the previous month, going from $2.33/MMBtu in August 2020 to $2.52/MMBtu in September 2020.
After four consecutive month-over-month increases, the New York Harbor residual oil price saw a decrease in price from the previous month, going from $8.72/MMBtu in August 2020 to $8.30/MMBtu in September 2020. As is the case most months, oil was largely priced out of most electricity markets for baseload operations.
A fuel price comparison based on equivalent energy content ($/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 ($15.45/MWh) was below the price of Central Appalachian coal ($27.24/MWh) on a $/MWh basis, with the spread between the two increasing compared to last month, mainly due to the decrease in the price of natural gas at Henry Hub. The price of natural gas at New York City ($10.78/MWh) was below the price of Central Appalachian coal ($27.24/MWh) during September 2020, with the spread between the two prices increasing 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.
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.
September wholesale electricity prices were bifurcated with prices lower in the east and higher in the west as a result of differing weather conditions. In the east, mild temperatures resulted in daily peak prices remaining below $40/MWh in New England (ISONE), New York City (NYISO), the Mid-Atlantic (PJM), the Midwest (MISO), Louisiana (into Entergy), and Texas (ERCOT). Extended record heat in the west pushed prices up to $120/MWh in the Southwest (Palo Verde), $151/MWh in Southern California (CAISO), $81/MWh in Northern California, and $105/MWh in the Northwest (Mid-C). Wholesale natural gas prices followed a somewhat similar pattern to electricity prices, with higher prices in the west driven by natural gas demand at power plants meeting higher electricity demand. Prices reached a nationwide high of $6.22/MMBtu in Southern California (SoCal Border), a 52-week locational high of $4.00/MMBtu in Northern California (PG&E Citygate), and $3.05/MMBtu in the Northwest (Sumas). The highest price east of the Mississippi River reached only $2.55/MMBtu in New England (ISONE). New 52-week locational low prices were set during the month at $0.95/MMBtu in New England (Algonquin) and $1.33/MMBtu in Louisiana at Henry Hub. New 12-month lows were missed by only a few pennies in the Midwest (Chicago Citygates) and in Texas (Houston Ship Channel).
Electricity system peak demand levels trended steadily down throughout September as temperatures cooled in all regions except California (CAISO) and Progress Florida, were temperatures remained summerlike and daily peak demand remained strong. In California, the 46,184 MW daily peak on September 8 was just 458 MW below CAISO’s 12-month daily peak high. In Progress Florida, the 11,431 MW daily peak on September 3 was just 124 MW below its 12-month daily peak high. In the Bonneville Power Administration, September 26’s daily peak demand high of 5,497 MW was a 12-month low for the region. As demand falls towards the end of the month and continuing into October, system operators begin the fall shoulder maintenance season in earnest as they prepare for the upcoming winter season.
Total U.S. coal stockpiles had a small month-over-month decrease of 0.5%, reaching 129 million tons in September 2020. This August to September fall in total U.S. coal stockpiles follows the normal seasonal pattern, as coal stockpiles decrease during the summer months so that coal-fired generators can meet the summer demand for electricity.
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 the previous month, going from 125 days of forward-looking days of burn in August 2020 to 116 days of burn in September 2020. For subbituminous units largely located in the western United States, the average number of days of burn increased slightly, going from 104 days of burn in August 2020 to 105 days of burn in September 2020.
|September 2020||September 2019||August 2020|
|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|
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.
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 PDF 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.
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.
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 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).
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.
Net generation statistics are grouped according to regions (see Electricity Monthly Update Explained Section) by generator type and fuel type. Generator type categories include:
Generation statistics are also displayed by fuel type. These include:
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 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:
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.