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Electricity Monthly Update

With Data for May 2022 Release Date: July 26, 2022 Next Release Date: August 24, 2022

Highlights: May 2022

  • Wholesale electricity prices set new 12-month high daily prices in the Mid-Atlantic (PJM), Midwest (MISO) and in Louisiana (into Entergy).

  • Electricity system daily peak demand rose sharply from April to May in all regions except California and the Northwest.

  • For the second consecutive month, both retail sales of electricity and total average revenues rose year over year in all four end use sectors.

Key indicators

Solar photovoltaic module shipments reach record high in 2021

Data source: U.S. Energy Information Administration, Form EIA-63B, Photovoltaic Module Shipments Report; Form EIA-860, Annual Electric Generator Report; Form EIA-860M, Monthly Update to Annual Electric Generator Report; Form EIA-861, Annual Electric Power Industry Report; and Form EIA-861M, Monthly Electric Power Industry Report.
Note: Data for 2021 are preliminary. Data on small-scale solar additions start in 2015.

U.S shipments of solar photovoltaic (PV) modules, based on preliminary 2021 data, increased by 21% to a record 26.3 million peak kilowatts (peak kW) in 2021 from 21.8 million peak kW in 2020. During the past decade, solar PV module shipments steadily increased, with significant year-over-year increases in 2015 (59%) and 2016 (35%). The general upward trend was interrupted in 2017 and 2018, however, when solar PV module shipments fell by 19% and 27%, respectively. In general, solar PV module shipments closely track utility-scale and small-scale PV capacity additions.

The increased growth in both utility–scale and small-scale solar markets drove the increase in solar module shipments in 2021.

Utility-scale: The United States added 13.2 gigawatts (GW) of utility-scale capacity, a record high and 25% more than 2020 capacity additions (10.6 GW). In 2021, utility-scale capacity additions rose sharply despite project delays, project postponements, supply-chain constraints, and volatile pricing (Wood Mackenzie/SEIA).

Small-scale: Small-scale solar capacity installations increased by 5.4 GW in 2021, up 23% from 2020 installations (4.4 GW). Most of the growth in the small-scale solar came from capacity additions in the residential sector; these installations grew at a record-level of 32%, totaling more than 3.9 GW, compared with 2.9 GW in 2020. Growth in the community solar market also appears to be contributing to the demand for solar PV modules, although this information is not part of EIA’s survey collection. Community solar U.S. installations rose 43% in 2021 compared with 2020 levels, according to the National Renewable Energy Laboratory (NREL). Nearly 80% of the growth in community solar installations occurred in five states: Florida, Minnesota, Massachusetts, New York, and Texas.

Data source: U.S. Energy Information Administration, Form EIA-63B, Photovoltaic Module Shipments Report.
Note: Data for 2021 are preliminary.

PV module cost reductions continued in 2021. The average value of solar PV module shipments (a surrogate for price) has decreased from $1.15 per peak kW in 2012 to $0.34 per peak kW in 2021. The value of solar PV shipments has decreased 70% during the past nine years; in particular, it decreased year over year by 11% from $0.38 in 2020 to $0.34 in 2021. The average value of solar PV modules may have decreased in 2021 because of low demand for modules in China, which outweighed the high demand from other markets such as the European Union, India, and the United States (NREL).

Data source: U.S. Energy Information Administration, Form EIA-63B, Photovoltaic Module Shipments Report.
Note: Data for 2021 are preliminary. State data collected from monthly respondents only.

In 2021, the top five destinations for PV shipments were California (5.09 million peak kW), Texas (4.31 million peak kW), Florida (1.21 million peak kW), Illinois (1.12 million peak kW), and Georgia (1.02 million peak kW). The top five states accounted for 48% of total shipments.

End Use: May 2022

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

Forty-six states and the District of Columbia saw increased revenue per kilowatt-hour (kWh) compared to last May. The largest percent increase was in Maine, up 49.5%, followed by Hawaii up 35.4%, and Oklahoma up 26.8%. Average revenue per kWh figures decreased in three states in May compared to last year. The largest decline was found in South Dakota, down 1.9%, followed by North Dakota down 1.8%, and Rhode Island down 1.8%. In the contiguous US, California had the highest average revenue at 21.32 cents per kWh, Pennsylvania had the median average revenue at 11.15 cents per kWh, while Idaho saw the lowest at 7.94 cents per kWh. The New England and Pacific Noncontiguous Census Divisions had the highest prices in the contiguous US on a regional basis.

Retail Service by Customer Sector
  Average Revenues/Sales (¢/kWh)   Retail Sales (thousand MWh)
End-use sector May 2022 Change fromMay 2021 May 2022 Change fromMay 2021 Year to Date
Residential 14.92 7.4% 110,482 8.9% 588,058
Commercial 12.14 11.4% 111,203 6.5% 536,408
Industrial 8.35 24.4% 84,892 2.7% 408,192
Transportation 10.79 7.1% 528 8.1% 2,748
Total 12.09 12.5% 307,106 6.2% 1,535,406
Source: U.S. Energy Information Administration

Total average revenues per kilowatt-hour (kWh) rose by 12.5% from last May, to 12.09 cents/kWh in May 2022. All four sectors saw increases in average revenues per kWh. The Industrial sector rose the most from last May, up 24.4%, followed by the Commercial sector, up 11.4%, the Residential sector, up 7.4%, and the Transportation sector, up 7.1%. Total retail sales were up 6.2% from May 2021. All four sectors saw increases in retail sales. The Residential sector rose the most from last May, up 8.9%, followed by the Transportation sector up 8.1%, the Commercial sector up 6.5%, and the Industrial sector, up 2.7%. This is the second consecutive month where both sales and price rose year over year in all four sectors.

Retail sales

Forty-four states saw an increase in retail sales volume in May 2022 compared to May 2021. Oklahoma had the highest percent year over year increase at 14.4%, followed by Rhode Island at 12.7%, and Texas rounded out the top three at 11.6%. The areas that saw larger increases in year over year sales were in the Southeast and the Great Plains. Six states and the District of Columbia saw a decrease in retail sales volume compared to last year. Idaho had the highest percent year over year decrease at 1.9%, followed by Colorado at 1.7%, and Maine at 1.3%. With the exception of Maine, the states experiencing a decrease in year over year sales were confined to the Rocky Mountain West and Pacific regions.

Thirty-eight states and the District of Columbia saw an increase in Cooling Degree Days (CDDs) from last May. The southern Great Plains and Midwestern states, and all states east of the Mississippi River saw a warmer May and, thus, an increase in CDDs. In the contiguous US, Colorado had the highest percent year over year increase at 225%, followed by Kansas at 209%, and Oklahoma at 187%. Eight states saw a decrease in CDDs in May 2022 compared to May 2021, with those states clustered in the Pacific Northwest and northern Great Plains. Oregon had the highest percent year over year decrease in CDDs at 92%, followed by Idaho at 67%, and North Dakota at 50%.

Resource Use: May 2022

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



Net electricity generation in the United States increased 7.7% compared to May 2021. This increase in electricity generation occurred, in part, because the country experienced above average temperatures this May compared to last year. This led to an increased demand for electricity in the climate-sensitive Residential (up 8.9%) and Commercial (up 8.1%) sectors. At the regional-level, all parts of the country saw a year-over-year increase in electricity generation, with Texas seeing the largest increase (17.7%) due to experiencing its second warmest May on record.

The year-over-year change in electricity generation from coal was mixed throughout the country. The Northeast, Southeast, and West all saw an increase in coal generation, while the MidAtlantic, Central, Florida, and Texas all saw a decrease in electricity generation from coal compared to May 2021. All regions of the country, except for the West, saw an increase in natural gas generation compared to a year ago.

Nuclear generation was relatively flat compared to May 2021. Electricity generation from other renewables increased in all regions of the country compared to the previous year, with Texas seeing the largest year-over-year increase in other renewables generation at 44.4%.

Fossil fuel consumption by region





The chart above compares coal consumption in May 2021 and May 2022 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 the West, saw their shares 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.

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 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 significantly from the previous month, going from $6.74/MMBtu in April 2022 to $8.36/MMBtu in May 2022. The natural gas price for New York City (Transco Zone 6 NY) also saw a significant increase from the previous month, going from $6.36/MMBtu in April 2022 to $7.77/MMBtu in May 2022. The average price of Central Appalachian coal increased from the previous month, going from $4.73/MMBtu in April 2022 to $5.29/MMBtu in May 2022.

The New York Harbor residual oil price saw a very slight decrease in price from the previous month, going from $16.05/MMBtu in April 2022 to $16.03/MMBtu in May 2022. As is the case in most months, oil was priced out of electricity markets for baseload operations in May 2022.

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 ($67.00/MWh) saw a significant increase from the previous month ($53.97/MWh) and was above the Central Appalachian coal price ($57.09/MWh) in May 2022. The price of natural gas at New York City ($62.27/MWh) saw a significant increase from the previous month ($50.92/MWh), and was very near the price of Central Appalachian coal ($57.09/MWh) during May 2022.

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: May 2022

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.

Wholesale prices



Wholesale daily electricity prices rose considerably from April to May at all selected hubs except the Northwest (Mid-C). Prices more than doubled in Texas (ERCOT), from an April high of $116/MWh to a May high of $274/MWh on May 13. New 12-month high daily prices were set on May 20 at $153/MWh in the Mid-Atlantic (PJM), at $120/MWh in the Midwest (MISO), and at $115/MWh in Louisiana (into Entergy). The high and rising wholesale electricity prices are the result of both hot weather, that covered most of the country with the exception of the Northwest and Upper Midwest regions, as well as high natural gas prices. Wholesale natural gas price highs in May were 9% to 29% higher than the highs recorded in April at all selected trading hubs except New England (Algonqiun), were monthly high prices fell 10% from April to May. New 12-month high natural gas prices were set in Northern California (PG&E Citygate) at $10.41/MMBtu, Louisiana (Henry Hub) at $9.44/MMBtu, Texas (Houston Ship Channel) at $9.05/MMBtu, the Midwest (Chicago Citygates) at $8.89/MMBtu, and in the Southwest (El Paso San Juan) at $8.85/MMBtu.

Electricity system daily peak demand


Electricity system daily peak demand rose considerably in tandem with temperatures from April to May. The maximum daily peak demand in May was 48% higher in New York State (NYISO), 45% higher in the Mid-Atlantic (PJM), 33% higher in the Midwest (MISO), 30% higher in New England (ISONE), 25% higher in Southern Company, 23% higher in Texas (ERCOT), and 14% higher in Progress Florida, compared to April maximum daily demand levels. Only in California (CAISO, up 3%) and in the Northwest (Bonneville Power Administration, down 12% due to one of the coolest May’s on record in Washington, Oregon, and Idaho) were daily peak demand days not significantly higher than in April. ERCOT’s 71,697 MW peak demand on May 31 wasn’t too far off the system’s 73,476 MW 52-week high demand nor its 74,533 MW all-time peak demand.

Electric Power Sector Coal Stocks: May 2022


Total U.S. coal stockpiles had a month-over-month increase of 1.7%, reaching 93 million tons in May 2022. This increase in total U.S. coal stockpiles follows the normal seasonal pattern whereby coal power plants increase their stockpiles during the spring months when electricity demand is lower on a seasonal basis. As in previous months, total U.S. coal stockpiles remain at a relatively low historical level.

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 decreased from the previous month, going from 86 days of forward-looking days of burn in April 2022 to 72 days of burn in May 2022. For subbituminous units largely located in the western United States, the average number of days of burn also decreased, going from 94 days of burn in April 2022 to 82 days of burn in May 2022.

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

    May 2022 May 2021   April 2022  
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 1,384 270 2,887 365 -52.1% 1,392 231 -0.6%
  Subbituminous . . . . . . . .
South Bituminous 12,155 63 16,232 77 -25.1% 12,737 77 -4.6%
  Subbituminous 3,503 45 5,610 65 -37.5% 3,316 55 5.6%
Midwest Bituminous 7,010 65 9,323 81 -24.8% 8,159 85 -14.1%
  Subbituminous 19,538 92 26,193 117 -25.4% 18,556 100 5.3%
West Bituminous 3,143 147 2,948 146 6.6% 2,868 142 9.6%
  Subbituminous 19,578 88 22,434 86 -12.7% 19,902 101 -1.6%
U.S. Total Bituminous 23,692 72 31,390 88 -24.5% 25,156 86 -5.8%
  Subbituminous 42,619 82 54,237 94 -21.4% 41,775 94 2.0%

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 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.

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.