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Electricity Monthly Update

With Data for August 2019  |  Release Date: October 24, 2019  |  Next Release Date: November 26, 2019

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Highlights: August 2019

  • Daily wholesale electricity prices reached $751/MWh in Texas (ERCOT) during August 2019.
  • A new all-time daily peak electricity demand record was set in Texas (ERCOT) on August 12, 2019.
  • Electricity generation in the Northeast decreased by 9.6% compared with the previous year, as the region experienced lower temperatures compared with the record high temperatures experienced in August 2018.

Key indicators

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

U.S. passes 1 gigawatt of operational battery capacity

In August 2019, U.S. battery energy storage capacity reached 1 gigawatt (GW). This significant milestone highlights the comparatively large increase in energy storage capacity added since 2015. It also sets a baseline for the substantial growth in capacity projected to come online by the end of 2023.

Operational battery capacity experienced large growth between 2015 and 2019, expanding by almost 670.7 megawatts (MW).

U.S. operational battery capacity, 2007-2018 Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report; Form EIA-860M, Monthly Update to the Annual Electric Generator Report.
Note: Data for 2019 are preliminary.

The trend of this capacity growth does not appear to be slowing, particularly in states such as Florida, New York, and Oklahoma. Notably, Florida expects to increase its current installed capacity from 14 MW to 409 MW by 2023. New York plans to have a battery storage capacity of 318 MW by 2023, an increase of 10 times its current level. In addition, in Oklahoma, the 250 MW Skeleton Creek Energy Center will be the first utility scale battery in the state and is expected to come online by 2023.

Current operational nameplate capacity by state varies significantly. California accounts for 25.4% of all operational battery storage capacity in the United States with 261.6 MW. Illinois ranks second and accounts for 12.9% of all operational battery storage capacity with 132.7 MW. Texas and Hawaii join these two states as the only other states with more than 50 MW of installed capacity at present.

U.S. installed battery capacity by state as of August 2019 Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report; Form EIA-860M, Monthly Update to the Annual Electric Generator Report.
Note: Data for 2019 are preliminary.

The U.S. Energy Information Administration (EIA) expects that the United States will reach 3,959.3 MW of operational energy storage capacity by 2023. California will continue to lead all states in installed battery storage. During the next four years, states with small energy storage capacities will also significantly increase their energy storage capacities. Massachusetts, which currently has 21.6 MW of installed capacity, will increase its energy storage capacity by nearly 11 times its current level. The Cranberry Point Energy Storage site (a 150 MW energy storage battery that will come online in 2023) will mostly drive this increase. Nevada, which is one of 17 states that currently does not have any utility scale battery installations, will have 95 MW of energy storage capacity by 2022.

U.S. proposed battery capacity by state from September 2019 through December 2023 Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report; Form EIA-860M, Monthly Update to the Annual Electric Generator Report.
Note: Data for 2019 are preliminary.


Principal Contributor:

Giovanni Naula
(Giovanni.Naula@eia.gov)

 

End Use: August 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 19 states and the District of Columbia in August compared to last year. The largest decline was found in the District of Columbia (down almost 8%) and Kansas and Ohio (both down over 5%). Thirty one states increased revenue per kilowatthour compared to last year, led by South Carolina (up almost 23%). This large increase, however, was due to a temporary rate reduction and one-time credit issued by a major South Carolina utility in August 2018, which drove down rates in August 2018 and help inflate the year-over-year change. Other states experiencing increases greater than 5% include Texas (9%), Arkansas (7%), Rhode Island (6.7%), Michigan (6.5%) and Iowa (5.2%).


Total average revenues per kilowatthour (kWh) in August 2019 were up by 0.8% from August 2018, to 11.10 cents/kWh. Average revenues for the Industrial sector rose the most, up by 2.6%. The Transportation sector followed, rising by 2.2%. The Residential sector had the smallest percentage increase, up by 0.3 %. The Commercial sector dropped slightly from August last year, down 0.3%. Total retail sales were down by 3.8% from August 2018, with all sectors showing a decrease in sales. The Industrial sector fell the most, dropping by 6.2%. The Commercial sector followed, down by 3.5%. The Transportation sector decreased by 3.3% and Residential sector dropped by 2.5%. This fall in sales was propelled in part by cooler temperatures relative to August 2018, as embodied in a 6.5% reduction in cooling degree days.

Retail sales



State retail sales volumes were down in 40 states and the District of Columbia in August compared to last year. California had the largest year-over-year decline, down almost 14%. The next four states had a 10%-or-greater drop in sales: Connecticut (down 12%), Maine (down almost 11%), New Jersey (down 10%), and Minnesota (down almost 10%). Ten states had retail sales volume increases in August, led by New Mexico (up almost 7%), Oklahoma (up over 4%), and Idaho (up over 3%).


Cooling Degree Days (CDD) were down in 32 states and the District of Columbia compared to last August. The greatest percentage drop in CDDs for August occurred in states in New England and the upper Mid-West. Maine had the highest drop, down over 60%. Three other states had an over-40%-drop in CDDs: Vermont (down 54%), Wisconsin (down almost 45%), and New Hampshire (down almost 44%). Sixteen states had an increase in CDDs in August. Colorado had the greatest increase in CDDs, up over 31%. Wyoming was the other state with a greater-than-30% increase in CDDs in August, up just over 30%. Only one state, Montana, had no change from the prior year.

 

Resource Use: August 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 decreased by 1.5% in August 2019 compared to the previous year. This decrease in electricity generation was primarily driven by cooler temperatures during the month compared to August 2018 in the more heavily populated Northeastern states. Most notably, many New England states experienced record high temperatures last August, while only experiencing above average temperatures during this August. All of this led to an overall decrease in the need for residential and commercial customer cooling and, by extension, the reduced need for electricity generation compared to a year ago. The only regions of the country that experienced an increase in electricity generation compared to the previous August were the Southeast and Texas, both of which saw much warmer temperatures compared to a year ago.

Electricity generation from coal decreased in all parts of the country compared to the previous year. All regions of the country, except for the Northeast, saw an increase in natural gas generation compared to August 2018. Nuclear generation as a whole decreased by 0.5%, compared to the previous year, while other renewables electricity generation increased in every region, except for the West, compared to the previous August. Wind and solar were the predominant energy sources that drove this overall increase in other renewables electricity generation compared to a year ago.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in August 2018 and August 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 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 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 slightly from the previous month, going from $2.42/MMBtu in July 2019 to $2.28/MMBtu in August 2019. The natural gas price for New York City (Transco Zone 6 NY) decreased compared to the previous month, going from $2.24/MMBtu in July 2019 to $1.90/MMBtu in August 2019. For the second consecutive month, the average price of Central Appalachian coal increased compared to the previous month, going from $2.63/MMBtu in July 2019 to $2.73/MMBtu in August 2019.

The New York Harbor residual oil price saw a decrease from the previous month, going from $12.48/MMBtu in July 2019 to $11.65/MMBtu in August 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 ($18.27/MWh) was below the price of Central Appalachian coal ($29.44/MWh) on a $/MWh basis, with the spread between the two increasing compared to the previous month. The price of natural gas at New York City ($15.23/MWh) was below the price of Central Appalachian coal ($29.44/MWh) during August 2019, with the spread between the two prices increasing, 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.

 

Regional Wholesale Markets: August 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 prices remained reasonable across most of the country given very high electricity system demand. This is in large part due to low natural gas prices, which serves as the fuel to marginal power generators in many electricity markets. 12-month low natural gas prices were set in New England (Algonquin) at $1.80/MMBtu, New York City (Transco Z6 NY) at $1.42/MMBtu, the Midwest (Chicago Citygates) at $1.87/MMBtu, Louisiana (Henry Hub) at $2.02/MMBtu, and Texas (Houston Ship Channel) at $1.96/MMBtu. The highest wholesale natural gas prices during the month were found in California, hitting $3.48/MMBtu in Southern California (SoCal Border) and $3.02/MMBtu in Northern California (PG&E Citygate).

Wholesale electricity prices were fairly moderate during the month given high electricity demand due to the aforementioned low natural gas prices, with one notable exception in Texas (ERCOT). Daily wholesale electricity prices peaked at $751/MWh in Texas (ERCOT) on August 16 towards the end of a period of hot weather and record power demand. Price spikes in Texas are partially the result of the market construction in ERCOT. In other power markets there are forward capacity markets where customers pay, and generators receive, payments for offering generating capacity into the market. This market design tends to lower price spikes and price volatility, but can also lead to some generators receiving payments whether they ever produce electricity or not. ERCOT lacks this forward capacity market, leading to higher price sensitivity in their “energy-only” market. In ERCOT, you only get paid when you produce electricity. Real-time prices in ERCOT, the most volatile, even spiked to the $9,000/MWh market price cap, though for just a couple hours. Outside of ERCOT, the highest daily wholesale electricity prices were found in the Southwest (Palo Verde), which hit $72/MWh, $48/MWh in the Northwest (Mid-C), and $48/MWh and $46/MWh in Southern and Northern California (CAISO), respectively.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system peak demand levels were very high across all systems in August, except Bonneville Power Administration, as a result of regional episodes of very warm temperatures driving up air-conditioning load. A new all-time daily peak demand record was set in Texas (ERCOT), which reached 74,533 MW on August 12, and new 12-month high daily peak demand levels were also set in Southern Company on August 13, and in Progress Florida and California (CAISO) on August 15. In Texas (ERCOT), the all-time daily peak demand before this year was set on July 19, 2018 at 73,473 MW. This previous-to-2019 record was surpassed this month on August 12 (74,533 MW), August 19 (73,793 MW), and again on August 26 (74,388 MW).

 

Electric Power Sector Coal Stocks: August 2019



Total U.S. coal stockpiles decreased very slightly in August 2019, only falling by 0.3% from the previous month. This was the smallest percentage decrease in August month-over-month coal stocks over the last 10 years. This very slow draw-down of total U.S. coal stockpiles reflects the shift away from coal used as a fuel for electricity generation during the summer months.

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 94 days of forward-looking days of burn in July 2019 to 105 days of burn in August 2019. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 63 days of burn in July 2019 to 74 days of burn in August 2019.

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

  August 2019   August 2018   July 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 3,831 189   2,706 84 41.6% 3,762 181 1.8%
  Subbituminous 162 181   168 168 -4.0% 163 206 -1.1%
South Bituminous 22,765 112   18,970 83 20.0% 22,398 95 1.6%
  Subbituminous 4,455 54   4,739 54 -6.0% 4,194 42 6.2%
Midwest Bituminous 10,180 87   9,657 82 5.4% 10,054 79 1.3%
  Subbituminous 21,385 87   27,153 86 -21.2% 21,373 76 0.1%
West Bituminous 3,888 84   4,794 100 -18.9% 3,875 79 0.3%
  Subbituminous 20,266 68   20,746 70 -2.3% 20,283 59 -0.1%
U.S. Total Bituminous 40,664 105   36,127 85 12.6% 40,089 94 1.4%
  Subbituminous 46,268 74   52,807 76 -12.4% 46,014 63 0.6%

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.