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Electricity Monthly Update

With Data for June 2019  |  Release Date: August 26, 2019  |  Next Release Date: September 24, 2019

Previous Issues

Highlights: June 2019

Key indicators

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

Residential electricity prices increase slightly since June 2017, but changes vary by region

The average U.S. residential price of electricity per kilowatthour (kWh) for the most recent rolling 12-month periods (June 2017 to May 2018 and June 2018 to May 2019) has increased slightly (0.3%) for the nation as a whole. Although the average national price has increased slightly, most state-level rates have decreased slightly (27). This divergence is caused by states with the largest price increases outpacing those with the largest price decreases. This trend can be seen at the census division level, where the Pacific Noncontiguous and the New England divisions experienced the largest increases in average prices (cents per kWh). Pacific Noncontiguous prices increased 7.5% and New England prices increased 4.2%. The other eight divisions all saw price decreases or increases ranging from decreases of 0.8% to increases of 2.2%. Altogether, five divisions saw increases and five divisions saw decreases.

Average price per kWh by U.S. Census Division Source: U.S. Energy Information Administration, Form EIA-861, Annual Electric Power Industry Report, Form EIA-861M, Monthly Electric Power Industry Report, Form EIA-861S, Annual Electric Power Industry Report (Short Form).

Notes: Data for 2017 are final; data for 2018 and 2019 are preliminary.

This trend is even clearer when looking at individual state totals. Five of the six largest electricity price increases came from either the Pacific Noncontiguous or the New England divisions. Specifically, the four states with the largest price increases—Rhode Island, Hawaii, Connecticut, and Massachusetts—are all members of one of those two census divisions. Rhode Island was the only state that saw a percent change greater than 10% at an increase of 10.2%. Hawaii was next largest at 9.0%, followed by Connecticut at 5.4% and Massachusetts at 4.6%. Texas rounds out the top five with a percent change of 4.1%.

Average price per kWh by U.S. Census Division Source: U.S. Energy Information Administration, Form EIA-861, Annual Electric Power Industry Report, Form EIA-861M, Monthly Electric Power Industry Report, Form EIA-861S, Annual Electric Power Industry Report (Short Form).

Notes: Data for 2017 are final; data for 2018 and 2019 are preliminary.

When looking at percent decreases in price, there is no region with large enough price decreases to balance out the sizeable increases seen in the Pacific Noncontiguous or New England Census divisions, as well as the moderate increases in the West South Central and Pacific Contiguous divisions. In addition, in terms of individual states with large percent decreases, there are no states to counterbalance the increases in Hawaii or Rhode Island. This lack of balance is partly why the U.S. total increased only slightly during this period.

The top five states in terms of decreased price per kilowatthour saw slight changes. The decreases experienced by these states were similar to the increases experienced by Connecticut, Massachusetts, and Texas in that they were only slight. Those states are: South Carolina at -5.4%, Arkansas at -5.1%, West Virginia at -4.6%, Utah at -4.0%, and Missouri at -3.6%. These states widely differ in region, unlike the states that saw significant increases. South Carolina and West Virginia are both in the South Atlantic Division, Arkansas is in the West South Central Division, Utah is in the Mountain Division, and Missouri is in the West North Central Division.

Average price per kWh by U.S. Census Division Source: U.S. Energy Information Administration, Form EIA-861, Annual Electric Power Industry Report, Form EIA-861M, Monthly Electric Power Industry Report, Form EIA-861S, Annual Electric Power Industry Report (Short Form).

Notes: Data for 2017 are final; data for 2018 and 2019 are preliminary.

The other 40 states and the District of Columbia all fall between an increase of 3.8% and a decrease of -3.4%. The majority of these states (28) and the District of Columbia saw an absolute (plus or minus) percent change less than 2%, and 13 of those states and the District of Columbia saw an absolute percent change of less than 1%. Overall, most of the United States saw relatively flat changes in electricity prices during the past two years. Those states that saw the highest increases outpaced those that saw the largest decreases and that led to the United States as a whole to see a slight increase in residential electricity prices.


Principal Contributors:

Connor Murphy
(Connor.Murphy@eia.gov)

Peter Wong
(Peter.Wong@eia.gov)

 

End Use: June 2019


Retail rates/prices and consumption

In this section, we look at what electricity costs and how much is purchased. Charges for retail electric service are based primarily on rates approved by state regulators. However, a number of states have allowed retail marketers to compete to serve customers and these competitive retail suppliers offer electricity at a market-based price.

EIA does not directly collect retail electricity rates or prices. However, using data collected on retail sales revenues and volumes, we calculate average retail revenues per kWh as a proxy for retail rates and prices. Retail sales volumes are presented as a proxy for end-use electricity consumption.

Average revenue per kWh by state



Average revenue per kilowatthour figures decreased in 23 states and the District of Columbia in June compared to last year. The largest declines were found in Oklahoma (down over 5%), Maryland and New Mexico (both down almost 5%). Twenty six states increased revenue per kilowatthour compared to last year, led by Maine (up over 14%). Only one state, Oregon, showed no change from the prior year.


Total average revenues per kilowatthour (kWh) in June 2019 were up by 0.1% from June 2018, to 10.80 cents/kWh. Average revenues for the Residential sector rose the most, up by 2.3%. The Commercial sector followed by rising slightly to 0.6%. The Industrial and Transportation sectors both declined from June last year, down 3.8% and 0.3% respectively. Total retail sales fell by 5.2% from June 2018. All sectors showed a drop in sales, with the Residential sector declining the most, by 7.7%. The Commercial sector followed, falling by 5.2%. The Industrial and Transportation sectors fell by 1.2% and 0.3%, respectively.

Retail sales



State retail sales volumes were down in 44 states and the District of Columbia in June compared to last year. Maine had the largest year-over-year decline, down almost 15%. Four other mid-Western states a 10%-or-greater drop in sales: Illinois (down 12%), Missouri (down almost 12%), Nebraska and Wisconsin (both down 10%). Six states had retail sales volume increases in June, led by Montana (up almost 7%), Florida (up almost 4%), and Hawaii (up 3%).


Cooling Degree Days (CDD) were down in 38 states compared to last June. Two had a greater-than-50% drop: Maine (down 73%) and Colorado (down 57%). Ten states and the District of Columbia had an increase of CDDs in June 2019 over the prior year, led by Oregon (up over 36%). Three other Pacific Northwest states made up the top 4: Montana (up almost 22%), Washington (up 20%), and Idaho (up almost 13%). Only one state, Rhode Island, had no change from the prior year.

 

Resource Use: June 2019

Supply and fuel consumption

In this section, we look at the resources used to produce electricity. Generating units are chosen to run primarily on their operating costs, of which fuel costs account for the lion's share. Therefore, we present below, electricity generation output by fuel type and generator type. Since the generator/fuel mix of utilities varies significantly by region, we also present generation output by region.

Generation output by region



map showing electricity regions

Net electricity generation in the United States was down 5.6% in June 2019 compared to the previous year. This decrease in electricity generation was primarily driven by cooler June 2019 temperatures compared to June 2018, which saw the third warmest U.S. June temperatures on record. This led to a decrease in the need for residential and commercial customer cooling and, by extension, the reduced need for electricity generation compared to a year ago. Additionally, at the regional-level, all regions experienced a decrease in electricity generation in June 2019 as cooler temperatures were common across the country relative to June 2018.

Electricity generation from coal, compared to June 2018, decreased in all parts of the country with the exception of the Northeast, where it is only 0.2% of total generation. Natural gas generation, up 4.6% nationally despite the downturn in total generation, expanded in four regions (Texas, Southeast, Florida, and MidAtlantic) and retracted in three regions (West, Central and Northeast) relative to June 2018. Nuclear generation as a whole decreased by 1.3%, compared to the previous year. The Southeast and Central regions were the only two regions that saw increases in nuclear generation compared to June 2018, as daily U.S. nuclear outages on average were higher in June 2019 (4.3 GW) versus June 2018 (3.7 GW).

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in May 2018 and May 2019 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption were similar to their respective changes in coal and natural gas generation.

The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. All regions of the country, except for the Northeast region, saw their shares of natural gas increase at the expense of coal. The Northeast region, however, has the lowest level of coal consumption of any of the regions. In the Northeast region, coal consumption represented only 0.8% of total fossil fuel consumption on an energy equivalent basis.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were similar to the changes seen in total coal and natural gas net generation in each region.

Fossil fuel prices




To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $/MMBtu basis as shown in the chart above. The average price of natural gas at Henry Hub decreased by 8.2% from the previous month, going from $2.70/MMBtu in May 2019 to $2.48/MMBtu in June 2019. For the fifth consecutive month, the natural gas price for New York City (Transco Zone 6 NY) decreased compared to the previous month, going from $2.34/MMBtu in May 2019 to $2.18/MMBtu in June 2019. The average price of Central Appalachian coal decreased by 18.8% from the previous month, going from $3.16/MMBtu in May 2019 to $2.57/MMBtu in June 2019.

For the second consecutive month, the New York Harbor residual oil price saw a decrease from the previous month, going from $12.71/MMBtu in May 2019 to $12.44/MMBtu in June 2019. As is the case most months, oil is used primarily for peaking operations and is largely priced out of the market for baseload operations.

A fuel price comparison based on equivalent energy content ($/MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. The price of natural gas at Henry Hub ($19.84/MWh) was below the price of Central Appalachian coal ($27.70/MWh) on a $/MWh basis, with the spread between the two decreasing for the second consecutive month, mainly due to the drop in the Central Appalachian coal price. The price of natural gas at New York City ($17.43/MWh) was below the price of Central Appalachian coal ($27.70/MWh) during June 2019, with the spread between the two prices decreasing due to the drop in the Central Appalachian coal price compared to the previous month.

The conversion shown in this chart is done for illustrative purposes only. The competition between coal and natural gas to produce electricity is more complex. It involves delivered prices and emission costs, the terms of fuel supply contracts, and the workings of fuel markets.

 

Regional Wholesale Markets: June 2019

The United States has many regional wholesale electricity markets. Below we look at monthly and annual ranges of on-peak, daily wholesale prices at selected pricing locations and daily peak demand for selected electricity systems in the Nation. The range of daily prices and demand data is shown for the report month and for the year ending with the report month.

Prices and demand are shown for six Regional Transmission Operator (RTO) markets: ISO New England (ISO-NE), New York ISO (NYISO), PJM Interconnection (PJM), Midwest ISO (MISO), Electric Reliability Council of Texas (ERCOT), and two locations in the California ISO (CAISO). Also shown are wholesale prices at trading hubs in Louisiana (into Entergy), Southwest (Palo Verde) and Northwest (Mid-Columbia). In addition to the RTO systems, peak demand is also shown for the Southern Company, Progress Florida, Tucson Electric, and the Bonneville Power Authority (BPA). Refer to the map tabs for the locations of the electricity and natural gas pricing hubs and the electric systems for which peak demand ranges are shown.

In the second tab immediately below, we show monthly and annual ranges of on-peak, daily wholesale natural gas prices at selected pricing locations in the United States. The range of daily natural gas prices is shown for the same month and year as the electricity price range chart. Wholesale electricity prices are closely tied to wholesale natural gas prices in all but the center of the country. Therefore, one can often explain current wholesale electricity prices by looking at what is happening with natural gas prices.

Wholesale prices



Selected wholesale electricity pricing locations

Wholesale electricity and natural gas prices were on the low end of the 12-month range at all selected trading hubs during the month of June. New 12-month low prices were also set in many locations. In wholesale electricity markets, 12-month lows were set in New England (ISONE), New York City (NYISO), the Mid-Atlantic (PJM), and in the Midwest (MISO). Louisiana (into Entergy) and Texas (ERCOT) were close to setting new 12-month low prices. In wholesale natural gas markets, new 12-month low prices were recorded during the month in New England (Algonquin), the Midwest (Chicago Citygates), Louisiana (Henry Hub), Texas (Houston Ship Channel), Southern California (SoCal Border), Northern California (PG&E Citygate), and the Northwest (Sumas). Prices at the Henry Hub in Louisiana, historically the proxy pricing point in the U.S, traded between $2.27/MMBtu and $2.54/MMBtu during the month.

Electricity system daily peak demand


Electric systems selected for daily peak demand

June electricity system peak demand levels were considerably higher than in May at all identified electricity systems as higher temperatures led to increased air conditioning demand. Demand has been particularly high in Florida, which has experienced prolonged above-normal temperatures. Florida logged its third-warmest June on record after setting its hottest May on record. Progress Florida set a new 12-month high peak demand of 11,850 MW on June 25, though this is well below its all-time peak demand of 13,394 MW.

 

Electric Power Sector Coal Stocks: June 2019



For the third consecutive month, U.S. coal stockpiles saw a month-over-month increase, going up 1% from May 2019 to 116 million tons in June 2019. June 2019 marks the first June since June 2009 that total coal stocks have increased month-over-month. Under previous market conditions, coal stocks tended to get burned down in June as the demand for power generation increases due to summer heat. However, with increased competition from natural gas and renewables, as well as coal retirements, it is possible that stocks are not being burned off as quickly as years past in the early summer months. The one exception to the June 2019 increase in coal stocks in terms of coal rank is lignite stocks that decreased by 0.7 million tons, or 21.6%, relative to May 2019.

Days of burn




The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn increased from the previous month, going from 82 days of forward-looking days of burn in May 2019 to 89 days of burn in June 2019. For subbituminous units largely located in the western United States, the average number of days of burn decreased, going from 63 days of burn in May 2019 to 62 days of burn in June 2019. Of note, the increase in days of burn for bituminous units is the first time bituminous days of burn have gone up month-over-month in June during the 2010 to 2019 period.

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

  June 2019   June 2018   May 2019  
Zone Coal Stocks (1000 tons) Days of Burn   Stocks (1000 tons) Days of Burn % Change of Stocks Stocks (1000 tons) Days of Burn % Change of Stocks
Northeast Bituminous 4,129 196   3,408 85 21.1% 3,956 194 4.4%
  Subbituminous 163 227   147 213 11.4% 163 250 0.0%
South Bituminous 23,997 88   21,552 62 11.3% 22,319 80 7.5%
  Subbituminous 4,739 45   6,246 55 -24.1% 5,071 50 -6.6%
Midwest Bituminous 11,195 81   10,802 73 3.6% 10,056 72 11.3%
  Subbituminous 22,647 73   31,480 79 -28.1% 22,226 73 1.9%
West Bituminous 3,776 71   5,317 99 -29.0% 3,971 79 -4.9%
  Subbituminous 19,618 58   24,961 69 -21.4% 19,636 58 -0.1%
U.S. Total Bituminous 43,097 89   41,080 70 4.9% 40,302 82 6.9%
  Subbituminous 47,167 62   62,833 72 -24.9% 47,096 63 0.2%

Source: U.S. Energy Information Administration

NOTE: Stockpile levels shown above reflect a sample of electric power sector plants, which were used to create the days of burn statistics. These levels will not equal total electric power sector stockpile levels.

 

Methodology and Documentation

General

The Electricity Monthly Update is prepared by the Electric Power Operations Team, Office of Electricity, Renewables and Uranium Statistics, U.S. Energy Information Administration (EIA), U.S. Department of Energy. Data published in the Electricity Monthly Update are compiled from the following sources: U.S. Energy Information Administration, Form EIA-826,"Monthly Electric Utility Sales and Revenues with State Distributions Report," U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," fuel spot prices from Bloomberg Energy, electric power prices from SNL Energy, electric system demand data from Ventyx Energy Velocity Suite, and weather data and imagery from the National Oceanic and Atmospheric Administration.

The survey data are collected monthly using multiple-attribute cutoff sampling of power plants and electric retailers for the purpose of estimation for various data elements (generation, stocks, revenue, etc.) for various categories, such as geographic regions. (The data elements and categories are "attributes.") The nominal sample sizes are: for the Form EIA-826, approximately 450 electric utilities and other energy service providers; for the Form EIA-923, approximately 1900 plants. Regression-based (i.e., "prediction") methodologies are used to estimate totals from the sample. Essentially complete samples are collected for the Electric Power Monthly (EPM), which includes State-level values. The Electricity Monthly Update is based on an incomplete sample and includes only regional estimates and ranges for state values where applicable. Using "prediction," it is generally possible to make estimates based on the incomplete EPM sample, and still estimate variances.

For complete documentation on EIA monthly electric data collection and estimation, see the Technical Notes to the Electric Power Monthly. Values displayed in the Electric Monthly Update may differ from values published in the Electric Power Monthly due to the additional data collection and data revisions that may occur between the releases of these two publications.

Accessing the data: The data included in most graphics can be downloaded via the "Download the data" icon above the navigation pane.Some missing data are proprietary and non-public.

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

Key Indicators

The Key Indicators in the table located in the "Highlights" section, are defined below. The current month column includes data for the current month at a national level. The units vary by statistic, but are included in the table. The "% Change from 2010" value is the current month divided by the corresponding month last year (e.g. July 2011 divided by July 2010). This is true for Total Generation, Residential Retail Price, Retail Sales, Degree-Days, Coal Stocks, Coal and Natural Gas Consumption.  The Henry Hub current month value is the average weekday price for the current month. The Henry Hub "% Change from 2010" value is the average weekday price of the same month from 2010 divided by the average weekday price of the current month.

Total Net Generation:  Reflects the total electric net generation for all reporting sectors as collected via the Form EIA-923.
Residential Retail Price:  Reflects the average retail price as collected via the Form EIA-826.
Retail Sales:  Reflects the reported volume of electricity delivered as collected via the Form EIA-826.
Degree-Days:  Reflects the total population-weighted United States degree-days as reported by the National Oceanic and Atmospheric Administration.
Natural Gas Henry Hub:  Reflects the average price of natural gas at Henry Hub for the month.  The data are provided by Bloomberg. 
Coal Stocks:  Reflects the total coal stocks for the Electric Power Sector as collected via the Form EIA-923.
Coal Consumption:  Reflects the total coal consumption as collected via the Form EIA-923.
Natural Gas Consumption:  Reflects the total natural gas consumption as collected via the Form EIA-923.
Nuclear Outages:  Reflects the average daily outage amount for the month as reported by the Nuclear Regulatory Commission's Power Reactor Status Report and the latest net summer capacity data collected on the EIA-860 Annual Generator Report.

Sector Definitions

The Electric Power Sector comprises electricity-only and combined heat and power (CHP) plants within the North American Industrial Classification System 22 category whose primary business is to sell electricity, or electricity and heat, to the public (i.e., electric utility plants and Independent Power Producers (IPPs), including IPP plants that operate as CHPs). The All Sectors totals include the Electric Power Sector and the Commercial and Industrial Sectors (Commercial and Industrial power producers are primarily CHP plants).

Degree Days

Degree-days are relative measurements of outdoor air temperature used as an index for heating and cooling energy requirements. Heating degree-days are the number of degrees that the daily average temperature falls below 65° F. Cooling degree-days are the number of degrees that the daily average temperature rises above 65° F. The daily average temperature is the mean of the maximum and minimum temperatures in a 24-hour period. For example, a weather station recording an average daily temperature of 40° F would report 25 heating degree-days for that day (and 0 cooling degree-days). If a weather station recorded an average daily temperature of 78° F, cooling degree-days for that station would be 13 (and 0 heating degree days).

Per Capita Retail Sales

The per capita retail sales statistics use 2011 population estimates from the U.S. Census Bureau and monthly data collected by the Energy Information Administration. The volume of electricity delivered to end users for all sectors in kilowatthours is divided by the 2011 population estimate for each state.

Composition of Fuel Categories

Net generation statistics are grouped according to regions (see Electricity Monthly Update Explained Section) by generator type and fuel type. Generator type categories include:

Fossil Steam:  Steam turbines powered by the combustion of fossil fuels
Combined Cycle:  Combined cycle generation powered by natural gas, petroluem, landfill gas, or other miscellaneous energy sources
Other Fossil:  Simple cycle gas turbines, internal combustion turbines, and other fossil-powered technology
Nuclear Steam:  Steam turbines at operating nuclear power plants
Hydroelectric:  Conventional hydroelectric turbines
Wind:  Wind turbines
Other renewables: All other generation from renewable sources such as geothermal, solar, or biomass
Other:  Any other generation technology, including hydroelectric pumped storage

Generation statistics are also displayed by fuel type. These include:

Coal:  all generation associated with the consumption of coal
Natural Gas:  all generation associated with the consumption of natural gas
Nuclear:  all generation associated with nuclear power plants
Hydroelectric:  all generation associated with conventional hydroelectric turbines
Other Renewable: all generation associated with wind, solar, biomass, and geothermal energy sources
Other Fossil: all generation associated with petroleum products and fossil-dervied fuels
Other:  all other energy sources including waste heat, hydroelectric pumped storage, other reported sources

Relative Fossil Fuel Prices

Relative fossil fuel prices are daily averages of fossil fuel prices by month, displayed in dollars per million British thermal units as well as adjusted for operating efficiency at electric power plants to convert to dollars per megawatthour. Average national heat rates for typical operating units for 2010 were used to convert relative fossil fuel prices.

Average Days of Burn

Average Days of Burn is defined as the average number of days remaining until coal stocks reach zero if no further deliveries of coal are made. These data have been calculated using only the population of coal plants present in the monthly Form EIA-923. This includes 1) coal plants that have generators with a primary fuel of bituminous coal (including anthracite) or subbituminous, and 2) are in the Electric Power Sector (as defined in the above "Sector definitions"). Excluded are plants with a primary fuel of lignite or waste coal, mine mouth plants, and out-of-service plants. Coal storage terminals and the related plants that they serve are aggregated into one entity for the calculation of Average Days of Burn, as are plants that share stockpiles.

Average Days of Burn is computed as follows: End of month stocks for the current (data) month, divided by the average burn per day. Average Burn per Day is the average of the three previous years' consumption as reported on the Form EIA-923.

These data are displayed by coal rank and by zone. Each zone has been formed by combining the following Census Divisions:

  • Northeast — New England, Middle Atlantic
  • South — South Atlantic, East South Central
  • Midwest — West North Central, East North Central
  • West — Mountain, West South Central, Pacific Contiguous

Coal Stocks vs. Days of Burn Stocks

The coal stocks data presented at the top of the Fossil Fuel Stocks section (“Coal Stocks”) will differ from the coal stocks presented in the Days of Burn section (“DOB Stocks”) at the bottom of the Fossil Fuel Stocks section. This occurs because Coal Stocks include the entire population of coal plants that report on both the annual and monthly Form EIA-923. The DOB Stocks only include coal plants that report on the monthly Form EIA-923 and have a primary fuel of bituminous (including anthracite) or subbituminous as reported on the Form EIA-860.