U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for June 2016 | Release Date: Aug. 24, 2016 | Next Release Date: Sep. 26, 2016
Highlights: June 2016
- For the first time in eighteen months, the price of natural gas at Henry Hub was above the price of Central Appalachian coal on a $/MWh basis.
- Tucson Electric set a new all-time peak demand record on June 20.
- Daily peak wholesale electric and natural gas prices were up nearly across the board in June from May.
|June 2016||% Change from June 2015|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Rural electric customers are the most vulnerable to power outagesSource: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861) 2015 early release
Power outages are more frequent and last longer for the customers of utilities servicing rural areas than for customers of municipal utilities. U.S. electric customers experienced an annual average of 1.3 outages in 2015. Customers of rural electric cooperative utilities on average experienced 2.1 outages. Customers of municipal utilities experienced an average of only one outage.
U.S. electric customer power outages lasted an average of 197 minutes in 2015. The average outage duration for customers of rural electric cooperative utilities was 287 minutes. Customers of municipal utilities experienced a significantly shorter average outage duration at 123 minutes.
These distribution outage statistics are not surprising because the service territories of rural cooperatives are much more spread out than those for municipals, and the investment in distribution wires is much larger per customer. The values for frequency and duration of outages for investor-owned utilities are between those for cooperatives and municipals because investor-owned utilities often have significantly larger service territories that include both rural areas and cities.
Utilities may designate if these outages occurred as a result of a major events such as snow storms, hurricanes, floods, or heatwaves. Utilities can also designate any period of outages that differ greatly from the five-year history of a given utility as a major event. Not all utilities are consistent in what they consider to be major events. For instance, a snow storm may be considered a major event by a utility in Virginia but not by a utility in Maine.
The chart above shows outage statistics designated with and without a major event. Major outage events (light blue) may skew the outage statistics because they are infrequent and random. Looking at the outage statistics without the major events (dark blue) provides a better sense of how well utilities are maintaining their distribution systems.
The relationship of outage measures among the three ownership types is similar to the discussion above when looking at the outage statistics without major events included. Because major events are rare, they do not increase the frequency value much. However, when they do occur, the severity of the event can prevent power from being restored for a much longer period of time.
In 2015, utilities in these three ownership groups that reported their outage information to EIA collectively made up only 28% of all utilities but accounted for about 72% of electricity sales in 2015.Source: U.S. Energy Information Administration, Annual Electric Power Industry Report (Form EIA-861) 2015 early release
Many of the standards for reporting these metrics were initially developed by the Institute of Electrical and Electronics Engineers (IEEE), a professional trade association for electric and information technologies and related fields. Most of the utilities reporting outage data use the IEEE standards, but some utilities have developed other approaches.
For those following the IEEE standard, in addition to options for including Major Event Days, outage frequency and duration values are reported to EIA for any interruption lasting longer than five minutes. Of those who reported reliability metrics, those entities that used IEEE standards represent 82% of electricity sales. The analyses above combined those who used IEEE standards and other methods.
End Use: June 2016
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 25 states in June compared to last year. The largest declines were found in Nevada (down nearly 13.2%), Mississippi (down 11.4%), and Hawaii (down 9.7%). Twenty-five states increased compared to last year, led by Iowa (up 6.7%), South Dakota (up 6.2%), Kentucky (up 5.9%), and West Virginia (up 5.8%).
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector June 2016 Change from June 2015 June 2016 Change from June 2015 Year to Date Residential 12.73 -1.5% 124,558 3.9% 653,220 Commercial 10.58 -2.1% 120,181 0.9% 649,033 Industrial 7.03 -1.0% 80,189 -4.3% 461,011 Transportation 9.58 -6.3% 633 3.5% 3,738 Total 10.53 -1.0% 325,562 0.7% 1,767,002
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour were down 1.0% to 10.53 cents in June compared to last year. All sectors were down on the month, from a 6.3% drop in the Transportation sector to a 1.0% drop in the Industrial sector. Retail sales were up slightly overall 0.7% to 325,562 gigawatthours (GWh). The Commercial, Transportation and Residential sectors showed slight gains of 0.9%, 3.5% and 3.9%, respectively, while the Industrial sector showed a decline of 4.3%.
State retail sales volumes were down in 23 states in June compared to last year. Virginia recorded the largest year-over-year decline, down 6.8%. West Virginia, South Carolina and New Hampshire had the next largest declines, all down 4.5 -5.9%. Twenty-Eight states had retail sales volume increases in June, led by Nebraska (up over 11%), Illinois (up to nearly 7%), and South Dakota (up over 6%).
Cooling Degree Days (CDD) measure the daily variation in average temperature above a 65 degree Fahrenheit baseline, chosen as a proxy for minimum heating or cooling energy demand. CDDs were higher across most of the country, up in 34 states compared to last June. The largest year-over-year increases were found in New England and the Great Lakes region, with Vermont, Wisconsin, Michigan and Maine the states with the highest CDD increases. Sixteen states and the District of Columbia had less CDDs than last June, with these states largely found in the Mid-Atlantic and far West. Alaska had the largest CDD decrease of any state, followed by Washington, Oregon, Idaho and Montana.
Resource Use: June 2016
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 generation in the United States increased 1.7% from the previous June. This occurred because the country, as a whole, experienced slightly higher temperatures this June compared to last year, which led to an increased need for residential cooling this year and thus, an increase in electricity generation. At the regional-level, all regions of the country saw an increase in electricity generation compared to June 2015, except for the Northeast and Southeast, which both saw electricity generation decrease slightly from the previous year.
Electricity generation from coal decreased in all regions of the country except for Texas and the Northeast. Natural gas generation increased from the previous year in all parts of the country except for the West, which saw an 8.5% decrease compared to June 2015. This decrease in natural gas generation occurred because the West, and more specifically the Northwest part of the country, saw a large increase in hydroelectric generation in June 2016.
Fossil fuel consumption by region
The chart above compares coal consumption in June 2015 and June 2016 by region and shows that the change in coal consumption mirrored the change in electricity generation from coal.
The second tab compares natural gas consumption by region and shows that changes in natural gas consumption from the previous June were similar to the changes in electricity generation from natural gas over the same period.
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. In June 2016, the share of natural gas consumption increased in almost all regions of the country at the expense of coal consumption compared to the previous year. The only outliers were in Texas and the Northeast, where coal consumption increased slightly at the expense of natural gas compared to the previous June.
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 increased significantly from the previous month, going from $1.97/MMBtu in May 2016 to $2.64/MMBtu in June 2016. The natural gas price for New York City (Transco Zone 6 NY) also increased, going from $1.61/MMBtu in May 2016 to $1.89/MMBtu in June 2016.
The New York Harbor residual oil price increased from the previous month, going from $7.02/MMBtu in May 2016 to $7.67/MMBtu in June 2016. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.
A fuel price comparison based on equivalent energy content ($/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. For the first time in eighteen months, the price of natural gas at Henry Hub was above the price of Central Appalachian coal on a $/MWh basis. This was mainly due to the large increase in the price of natural gas at Henry Hub. The price of natural gas at New York City on a $/MWh basis was still below the price of Central Appalachian coal for a fourth consecutive month, however, the spread between the two prices decreased due to the increase in the price of natural gas at New York City.
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 2016
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 prices moved higher in June compared to the particularly low prices recorded in May. This was partially the result of higher natural gas prices (though prices are still low relative to historical levels) and partially due to higher electricity system demand levels. The highest electricity price last month was just over $43/MWh in MISO. This month, wholesale electricity prices reached $58/MWh in the Southwest (Palo Verde), $56/MWh in Southern California (CAISO), $48/MWh in Texas (ERCOT), $46/MWH in Northern California (CAISO) and nearly $45/MWh in the Mid-Atlantic (PJM).
The highest wholesale natural gas price in May reached only $2.17/MMBtu in Northern California (PG&E Citygate). This month, every hub except the Mid-Atlantic (Tetco M-3) exceeded that high price at PG&E Citygate. Natural gas prices reached $3.26/MMBtu at Northern California (SoCal Border), $3.24/MMBtu in New England (Algonquin) and Southern California (SoCal Border) reached $3.10/MMBtu, which was also a new 12-month high at that hub.
Electricity system daily peak demand
Electricity system daily peak demand increased considerably in June, with peak demand levels 5-40% higher in each region than in May. A new all-time record was also set in Tucson Electric on June 20 in the midst of a record heat wave. Temperatures in Tucson reached 115 degrees on Sunday, June 19, the third-hottest day ever in Tucson and the hottest since 1994 and hit 111 degrees on Monday, June 20 when Tucson Electric's new all-time demand record of 3,211 MW was set (electricity demand is highest on weekdays as commercial and industrial activities add to residential demand). Progress Florida approached record territory on June 13 with demand reaching 13,152 MW in the midst of near-record high temperatures in that area. Daily peak electricity demand in Southern Company on June 25 and Texas (ERCOT) on June 15 also exceeded 90% of all-time high demand levels in those respective regions.
Electric Power Sector Coal Stocks: June 2016
In June, U.S. coal stockpiles decreased to 185 million tons, down 5.2% from the previous month. As a whole, U.S. coal stockpiles are still at relatively high levels due to the mild winter experienced earlier in the year and also becaue coal continues to lose market share to natural gas in most regions of the country.
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 87 days of burn in May to 86 days of forward-looking days of burn in June. For subbituminous units largely located in the western United States, the average number of days of burn decreased, going from 84 days in May to 79 days in June.
Coal stocks and average number of days of burn for non-lignite coal by region (electric power sector)
|June 2016||June 2015||May 2016|
|Zone||Coal||Stocks (1000 tons)||Days of Burn||Stocks (1000 tons)||Days of Burn||% Change of Stocks||Stocks (1000 tons)||Days of Burn||% Change of Stocks|
Source: U.S. Energy Information Administration
NOTE: Stockpile levels shown above reflect a sample of electric power sector plants, which were used to create the days of burn statistics. These levels will not equal total electric power sector stockpile levels.
Methodology and Documentation
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.
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.
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).
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 combusion 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.