Daily wholesale electricity prices were highest in the West, reaching $312/MWh in the Southwest (Palo Verde) and $300/MWh in the Northwest.
Daily peak demand was lower on eight of the nine selected electricity systems in September, with California (CAISO) the only system recording a higher daily peak in September than in August.
Total U.S. coal stockpiles had a month-over-month decrease of 4.8%, reaching 80 million tons in September 2021. This is now the lowest level of total U.S. coal stockpiles recorded for the month since these data were collected using the power plant operations report beginning in 2001.
On average, U.S. electricity customers experienced just over eight hours of electric power interruptions in 2020, the most since we began collecting electricity reliability data in 2013. The average U.S. electricity customer experienced nearly 20 more minutes of power interruptions in 2020 than in 2017, the year with second-longest duration of interruptions in our records. When major events are excluded, the average duration of interruptions customers experienced annually from 2013 to 2020 was consistently around two hours.
Different factors cause power interruptions, including weather, vegetation patterns, and utility practices. Utilities can report interruption duration values with major events (including snowstorms, wildfires, and hurricanes), without major events, or both.
One metric used to measure the reliability of U.S. electric utilities is the System Average Interruption Duration Index (SAIDI), which measures the total time an average customer experiences a non-momentary power interruption in a one-year period. SAIDI is often paired with the System Average Interruption Frequency Index (SAIFI), which measures the frequency of interruptions. Electricity reliability metrics are explained further in our video guide on SAIDI and SAIFI and are available in our Annual Electric Power Industry Report.
Electricity customers in the District of Columbia, Arizona, Nevada, North Dakota, and South Dakota had the shortest total time of electric power interruptions in 2020, ranging from 44 minutes in the District of Columbia to 101 minutes in South Dakota.
Customers in Alabama, Iowa, Connecticut, Oklahoma, and Louisiana experienced the most time with interrupted power in 2020, ranging from almost 29 hours in Alabama to 60 hours in Louisiana. The long interruptions were largely because of major weather events. The United States experienced 14 hurricanes in 2020 and 11 major storms, making for an extremely disruptive Atlantic weather season.
Louisiana experienced the most active storm season in the state’s history, including Hurricane Laura, which was the state’s second-most costly storm after Hurricane Rita in 2005. Alabama was also hit with several hurricanes. Tropical Storm Isaias severely affected Connecticut, leaving about 750,000 electricity customers without power, some for over a week.
A derecho affected Iowa and other parts of the Midwest, causing widespread power interruptions and damaging grid infrastructure. Damages from the derecho resulted in the early retirement of Iowa’s only nuclear power plant, the Duane Arnold Energy Center, ahead of the plant’s scheduled October 2020 decommissioning. In Oklahoma, an ice storm in October 2020 resulted in widespread power interruptions.
In addition to power interruption duration, reliability can also be measured in terms of the frequency of power interruptions. Maine, which historically has the most frequent electric power interruptions (averaging 3.1 interruptions annually from 2013 through 2020—the most in the nation), is a heavily forested state where power interruptions resulting from falling tree branches are common. In 2020, Maine saw the highest average number of power interruptions per customer (3.9 interruptions). West Virginia, another heavily forested state with a history of frequent interruptions (averaging 2.5 interruptions per year since 2013—the second most in the nation), experienced 2.4 interruptions per customer in 2020. The Gulf States of Louisiana (3.2 interruptions), Mississippi (2.5 interruptions), and Alabama (2.4 interruptions) also experienced a higher-than-average number of interruptions per customer, largely due to major events. In contrast, the District of Columbia (0.4 interruptions), Nevada (0.7 interruptions), Nebraska (0.8 interruptions), Arizona (0.8 interruptions), and Wisconsin (0.8 interruptions) where well below the U.S. average of 1.4 power interruptions per customer.
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.
Forty-six states and the District of Columbia saw increased revenue per kilowatthour (kWh) compared to last September. The largest percent increase was in Louisiana, up 20.5%, followed by Missouri and Oklahoma, up 16.0% and 15.0%, respectively. Average revenue per kWh figures decreased in four states in September compared to last year. The largest decline was found in Wyoming, down by 3.1%, followed by Nebraska, Nevada, and North Carolina, down 2.0%, 1.8%, and 0.5%, respectively. In the contiguous US, California had the highest average revenue at 21.57 cents per kWh, while Idaho saw the lowest at 8.13 cents per kWh.
|Average Revenues/Sales (¢/kWh)||Retail Sales (thousand MWh)|
|End-use sector||September 2021||Change fromSeptember 2020||September 2021||Change fromSeptember 2020||Year to Date|
|Source: U.S. Energy Information Administration|
Total average revenues per kilowatt-hour (kWh) rose by 6.4% from last September, to 11.69 cents/kWh in September 2021. All four sectors saw increases in average revenues per kWh. The Industrial sector rose the most from last September, up 10.1%, followed by the Transportation sector, up 8.3%. The Commercial sector was up 6.7% and lastly, the Residential sector rose by 5.2%. Total retail sales were up 4.2% from September 2020. Three of the four sectors saw increases in retail sales. The Commercial sector rose the most from last September, up 4.9%, followed by the Industrial sector, up 4.8%, and the Residential sector, up 3.1%. The Transportation sector saw a decrease of 1.7% in retail sales.
Forty-four states saw an increase in retail sales volume in September 2021 compared to September 2020. This uptick was driven in part by warmer weather in most of the country, particularly in the Midwest and Great Plains, compared to September 2020. Oklahoma had the highest percent year over year increase at 15.0%, followed by Kansas at 11.6%, and Illinois rounded out the top three at 9.1%. Parts of the Western U.S. and Louisiana were the only areas that saw a decrease in year over year sales. Idaho had the highest percent year over year decrease at 2.9%, followed by Louisiana at 2.8%, and California at 1.9%.
Thirty states and the District of Columbia had an increase in Cooling Degree Days (CDDs) from last September. The Mid Atlantic, Midwest, and Rocky Mountain states saw the largest increase in CDD’s from last year. In the contiguous US, Wisconsin had the highest percent year over year increase at 300%, followed by Illinois at 155%, and North Dakota at 142%. Nineteen states saw a decrease in CDDs in September 2021 compared to September 2020. The West Coast, Northeast, and Southeastern states saw a cooler September with less CDDs compared to last year. Maine had the highest percent year over year decrease at 63%, followed by Washington at 56%, and Oregon at 39%.
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 in September 2021 increased by 4.4% compared to September 2020. This increase in electricity generation likely occurred because the country experienced much warmer temperatures this September compared to last year. This led to an increased need for residential cooling and thus an increased demand for electricity generation. At the regional-level, Florida and the Western region were the only areas of the country that saw a year-over-year decrease in electricity generation.
All parts of the country, except for Florida, saw an increase in electricity generation from coal compared to the previous year. The change in electricity generation from natural gas was more mixed, with the Northeast, Southeast, Florida, and Texas all seeing an increase in natural gas generation compared to September 2020, while the MidAtlantic, Central, and West all saw a decrease in natural gas generation.
Nuclear generation decreased by 1.9% from the previous year. Although, conventional hydroelectric electricity generation increased in most areas of the country, with only Texas and the West seeing an overall decrease, the large drop in hydroelectric generation in the West (-16.8%) helped drive down total hydroelectric generation by 3.8%. Electricity generation from other renewable sources was up in all parts of the country (21%), with the MidAtlantic region seeing the largest percent change (33.8%) compared to the previous September.
The chart above compares coal consumption in September 2020 and September 2021 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 and Texas, saw their share of coal increase at the expense 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.
To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average spot 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 $4.15/MMBtu in August 2021 to $5.28/MMBtu in September 2021. The natural gas price for New York City (Transco Zone 6 NY) also saw an increase from the previous month, going from $3.96/MMBtu in August 2021 to $4.09/MMBtu in September 2021. The average price of Central Appalachian coal increased from the previous month, going from $2.69/MMBtu in August 2021 to $2.90/MMBtu in September 2021.
The New York Harbor residual oil price saw an increase in price from the previous month, going from $13.10/MMBtu in August 2021 to $14.22/MMBtu in September 2021. As is the case most months, oil was largely priced out of most electricity markets for baseload operations.
A fuel price comparison based on equivalent energy content ($/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 Henry Hub natural gas price ($42.26/MWh) saw an increase from the previous month (33.25/MWh) and remained above the Central Appalachian coal price ($31.36/MWh) in September 2021. The price of natural gas at New York City ($32.73/MWh) also saw an increase from the previous month ($31.71/MWh) and this caused it to remain above the price of Central Appalachian coal ($31.36/MWh) during September 2021.
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, 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 up across the board from August. The highest prices in the country were all found in the West. Daily electricity prices reached $312/MWh in the Southwest (Palo Verde), $300/MWh in the Northwest (Mid-C), $231/MWh in Southern California (CAISO), and $152/MWh in Northern California (CAISO). Prices were considerably lower in the Eastern United States, with high daily prices ranging from $61-$82/MWh in New England (ISONE), New York State (NYISO), the Mid-Atlantic (PJM), the Midwest (MISO), Louisiana (into Entergy), and Texas (ERCOT). Wholesale natural gas markets followed a similar pattern, with prices higher west of the Rocky Mountains than in the East and Midwest. The highest daily natural gas price was recorded in Southern California, with prices hitting $18.66/MMBtu in Southern California (SoCal Border). The second highest price was found in Northern California at $7.42/MMBtu at PG&E Citygate, and the third highest price was set in the Northwest at $5.98 at the Sumas trading hub. High prices ranged from $5.18-$5.70/MMBtu east of the Mississippi and ranged from $4.59-$5.94/MMBtu at the Henry Hub in Louisiana.
Electricity system daily peak demand was lower on eight of nine selected electricity systems in September, with California (CAISO) the only system recording a higher daily peak in September than in August. Daily peak demand reached 42,469 MW in CAISO, 3% higher than the highest daily peak in August. On all other selected electricity systems, daily peak demand in September was anywhere from 2% lower in Texas (ERCOT) to 20% lower in New England (ISONE) relative to August peak demand.
Total U.S. coal stockpiles had a month-over-month decrease of 4.8%, reaching 80 million tons in September 2021. This is now the lowest level of total monthly U.S. coal stockpiles recorded since these data were collected using the power plant operations report beginning in 2001.
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 slightly from the previous month, going from 86 days of forward-looking days of burn in August 2021 to 88 days of burn in September 2021. For subbituminous units largely located in the western United States, the average number of days of burn remained unchanged from the previous month at 82 days of burn.
|September 2021||September 2020||August 2021|
|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.