Residential retail choice programs give customers the option to purchase the energy component of their electricity service from one entity (an energy-only provider, for example, a retail power marketer), while a second entity (for example, a utility) delivers the electricity to the customer. These programs differ from traditional utility services, in which a full-service provider is the default choice for customers, meaning their utility both purchases their electricity service and handles the delivery to their home. Total U.S. residential retail choice customers have steadily increased during the past few years from their recent 2016 low of 10.6 million to 11.1 million in 2018. Residential retail choice customers peaked in 2014, reaching a high of 11.4 million.
Since 2014, several states have seen marked declines in the number of residential retail choice customers, while others states more recently have seen their penetration rates significantly increase. Illinois and Connecticut have seen the greatest declines in their penetration rates, or the percentage of total residential customers that have chosen an energy-only provider. Illinois’s penetration rate has dropped from 57.3% in 2014 to 34.1% in 2018 following the polar vortex, when many customers experienced large increases in their monthly electric bills as a result of the spike in prices. Similarly, the share of residential retail choice customers in Connecticut dropped from 36.4% in 2014 to 25.8% in 2018. In 2015, state utility regulators in Connecticut passed a ban on variable rate service contracts, which could have slowed growth. In contrast, California and Massachusetts added 616,353 and 168,914 retail choice customers, respectively, from 2017 to 2018. As a percentage of the total retail choice market, California retail choice customers went from only 0.4% of the residential market in 2012 to 11.3% in 2018, while the share of retail choice customers in Massachusetts grew from 34.7% in 2017 to 40.7% in 2018, ranking second nationally and only surpassed by Ohio (47.7%).
The significant growth in California’s residential retail choice market since 2012 is primarily a result of the formation of community choice aggregators (CCAs). CCA programs allow local governments to exercise greater buying power in purchasing electricity from retail power marketers on behalf of community residents and businesses while still having the power delivered by the local utility. Seven states (California, Illinois, Ohio, Massachusetts, New Jersey, New York, and Rhode Island) have authorized CCA programs, which also must be approved at the local government level and normally have opt-out provisions, which allow retail customers to not participate if they so choose. CCA formation has been significant in California in particular and, as such, large numbers of customers within these communities are moving to retail choice through CCAs. Between 2016 and 2018, the City and County of San Francisco, Los Angeles County, and Santa Clara County are just a few of the communities that launched their own CCAs.
During the same time period, only Massachusetts achieved similar growth in the penetration rate of residential retail choice. The relatively high electricity prices in the state could be a contributing factor; residential electricity prices ranked as the third highest in the country in 2018. Residential retail choice customers expanded by 18% in 2018 (1,114,652) compared with 2017 (945,738). Municipal aggregation has also been popular in Massachusetts for cities that choose to shop for their own power. However, in January 2020 the Massachusetts attorney general reportedly asked the state Department of Public Utilities to evaluate the impacts of retail choice markets on low-income consumers. The attorney general has also reached settlements with a few key players in the industry to restrict certain marketing practices directed at consumers.
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 18 states and the District of Columbia in May compared to last year. The largest decline was found in Florida, down over 17%. Thirty two states increased revenue per kilowatthour compared to last year, led by Michigan (up almost 12%) and Vermont (up almost 9%).
|Average Revenues/Sales (¢/kWh)||Retail Sales (thousand MWh)|
|End-use sector||May 2020||Change fromMay 2019||May 2020||Change fromMay 2019||Year to Date|
|Source: U.S. Energy Information Administration|
Total average revenues per kilowatthour (kWh) rose 0.3% in May to 10.45 cents/kWh. All sectors dropped from last May, with the Industrial sector leading the decline, down by 3.3%. The Transportation sector followed, dropping by 2.1%. The Residential and Commercial sectors fell by 1.5% and 0.7%, respectively. Total retail sales were down by 7.4% from May 2019. Three sectors fell from a year ago. The Transportation dropped the most, down by 26.0%. The Commercial and Industrial sectors were both down by 15.8% and 11.7%, respectively. The Residential sector rose by 5.5%.
State retail sales volumes were down in 43 states and the District of Columbia in May compared to last year. Maine had the largest year-over-year decline, down over 18%. The District of Columbia, Wyoming, and South Carolina followed, each falling by over 15%. Seven states had retail sales volume increases in May, led by Arizona, which rose by over 21%.
Cooling Degree Days (CDD) were down in 24 states and the District of Columbia compared to last May. The greatest percentage drop in CDDs occurred in Maryland, which was down over 62%. The District of Columbia, Virginia, and North Carolina followed, each dropping more than 55%. Twenty states had an increase in CDDs in May, with Vermont, Michigan, Colorado, and New Hampshire all seeing the largest increases in CDDs compared to the previous May. Two states, Connecticut and Rhode Island, had no change in CDDs from May 2019.
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 7.6% in May 2020 compared to the previous year. This decrease in electricity generation was primarily driven by reduced demand for electricity generation caused by business shutdowns and changes to normal routines related to mitigation efforts for the 2019 novel coronavirus disease (COVID-19). At the regional-level, all parts of the country, except for the West, experienced a year-over-year decrease in electricity generation. The Western region was the loan outlier and saw electricity generation increase 3% compared to the previous May. This occurred because many states in the West experienced significantly above average temperatures this May and significantly below average temperatures last May, which caused a substantial year-over-year increase in the demand for residential cooling and in turn, an increase in electricity generation compared to May 2019.
Electricity generation from coal decreased in all parts of the country compared to the previous year. The change in electricity generation from natural gas was much more mixed, with the MidAtlantic, Central, and Western regions all seeing an increase in natural gas generation, while the Northeast, Southeast, Florida, and Texas all saw a decrease in natural gas generation. Nuclear generation as a whole was down 4.1% compared to a year ago. Other renewables generation increased in all regions of the country, with Florida seeing the largest change (up 23.9%) compared to May 2019.
The chart above compares coal consumption in May 2019 and May 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. All regions of the country saw their shares of natural gas increase mainly 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 was $1.78/MMBtu in May 2020 and showed no change from the previous month. The natural gas price for New York City (Transco Zone 6 NY) saw a month-over-month decrease, going from $1.57/MMBtu in April 2020 to $1.40/MMBtu in May 2020. The average price of Central Appalachian coal decreased slightly from the previous month, going from $2.37/MMBtu in April 2020 to $2.35/MMBtu in May 2020.
After observing month-over-month price decreases throughout this year, the New York Harbor residual oil price final saw an increase in price from the previous month, going from $5.35/MMBtu in April 2020 to $6.32/MMBtu in May 2020. As is the case most months, oil was largely priced out of most electricity markets for baseload operations. However, the drastic decrease in the price of oil has made operations at peaking power plants more economical.
A fuel price comparison based on equivalent energy content ($/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 ($14.28/MWh) was below the price of Central Appalachian coal ($25.42/MWh) on a $/MWh basis, with the spread between the two decreasing slightly compared to last month, mainly due to the slight decrease in the price of Central Appalachian coal. The price of natural gas at New York City ($11.18/MWh) was below the price of Central Appalachian coal ($25.42/MWh) during May 2020, with the spread between the two prices increasing slightly, mainly due to the decrease 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.
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 electricity and natural gas prices remained low in May, with all selected trading hubs at or near the low end of their respective 12-month price range. Wholesale electricity prices hit new 12-month lows of $14.40/MWh in New England (ISONE), $14.13/MWh in New York City (NYISO), $15.48/MWh in the Mid-Atlantic (PJM), $2.75/MWh in the Southwest (Palo Verde), $7.39/MWh in Southern California (CAISO), $7.80/MWh in Northern California (CAISO), and $-0.13/MWh in the Northwest (Mid-C). Negative power prices in the Northwest are not all that uncommon during the spring as mild weather and surging hydroelectric output, sometimes also coupled with high wind generation, can depress prices dramatically in this region. The highest recorded price during the month was only $69/MWh in Texas (ERCOT), just a fraction of the $975/MWh 12-month high in that region. Wholesale natural gas prices hit a new 12-month low in New England (Algonquin) at $1.06/MMBtu and stayed below $2/MMBtu at all selected hubs except Northern California (PG&E Citygate), which reached $2.95/MMBtu on May 6. Prices at the Henry Hub in Louisiana stayed in a low and tight range of $1.56-$1.92/MMBtu during the month.
Electricity system peak demand levels that were extremely low in much of the country throughout April fell even further on many systems in May. Below, to greatly-below, average temperatures in nearly every state east of the Rockies meant mild temperatures and less air-conditioning demand. New 12-month low daily peak demand levels were set in New York State (NYISO) and the Mid-Atlantic (PJM) on May 2, in the Midwest (MISO) and Southern Company on May 9, and in New England (ISONE) on May 24. The relative highest daily peak demand occurred in Texas (ERCOT) and on the Tucson Electric systems. This is probably no surprise and a result of the fifth hottest May on record in Arizona and much-above-average temperatures in Texas during the month that drove an increase in air-conditioning demand in these regions.
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.