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Electricity Monthly Update

With Data for April 2016  |  Release Date: June 24, 2016  |  Next Release Date: July 25, 2016

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Highlights: April 2016

Key Indicators

  April 2016 % Change from April 2015
Total Net Generation
(Thousand MWh)
293,317 -0.3%
Residential Retail Price
(cents/kWh)
12.43 -1.7%
Retail Sales
(Thousand MWh)
266,376 -2.3%
Heating Degree-Days 317 5.3%
Natural Gas Price, Henry Hub
($/MMBtu)
1.96 -26.6%
Natural Gas Consumption
(Mcf)
757,330 9.1%
Coal Consumption
(Thousand Tons)
39,064 -19.5%
Coal Stocks
(Thousand Tons)
196,163 17.0%
Nuclear Generation
(Thousand MWh)
62,365 4.4%



The total output over a 12-month period of U.S. electric generators fueled by natural gas surpassed those fueled by coal for first time in January 2016

The rolling 12-month total of natural gas-fired generation in the United States ending in January 2016 was higher than the rolling total for coal-fired generation for the first time. Demonstrating that this was not a one-month anomaly, the running 12-month totals for natural gas continued to be higher in February, March, and April 2016.

April 2015 was the first month that electricity generated from natural gas-fired sources was greater than generation from coal-fired sources. Coal-fired generation was greater the next two months, but every month through April 2016 thereafter - with the exception of January 2016 - natural gas-fired generation was greater. A recent EIA Short-Term Energy Outlook forecasts that 2016 will be the first calendar year when natural gas-fired generation will surpass coal-fired generation in the United States.

Source: U.S. Energy Information Administration, Form EIA-923 Power Plant Operations Report

The competition between coal and natural gas generators to produce electricity on a day-to-day basis involves careful consideration of delivered fuel prices and emission costs, operations and maintenance (O&M) costs, the terms of fuel supply contracts, and the workings of fuel markets. In the longer term, market participants must evaluate the relative capital cost of new capacity, as well as their expectations regarding fuel, O&M, and emission control costs. Based on all these factors, electricity generators making these complicated decisions have turned more to natural gas recently.

As recently as March 2011, the total electricity output of U.S. coal-fired generators was more than double that of natural gas-fired generators. Over the past five years, the gap has closed. The recent decline in the generation share of coal and the concurrent rise in the share of natural gas appears to have been primarily the result of lower natural gas prices.


Principal Contributor:

Ronald Hankey
(Ronald.Hankey@eia.gov)

 

End Use: April 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 29 states and the District of Columbia in April compared to last year. The largest declines were found in Nevada (down 15%), Hawaii (down 14%), and Mississippi (down 13%). Hawaii's electricity sector is largely fueled by petroleum products shipped from the U.S. mainland and imported sources, and has benefitted greatly from the drop in world oil prices over the last several years. Its 22.68 cents per kilowatthour average in April was the lowest average since September 2009 and down nearly 40% from a high of 34.61 cents in July 2012. Twenty-two states increased compared to last year, led by West Virginia (up 9%), Delaware (up 8%), Alaska (up 6%), and South Dakota (up 5%).

Total average revenues per kilowatthour were down 2.1% to 9.81 cents in April compared to last year. All sectors were down on the month, from a 4.3% drop in the Transportation sector to a 1.7% drop in the Residential sector. Retail sales were down 2.3% to 266,376 gigawatthours (GWh), with declines also across all sectors.

Retail sales



State retail sales volumes were down in 39 states and the District of Columbia in April compared to last year. Idaho recorded the largest year-over-year decline, down just over 10%. The District of Columbia, Delaware, and Washington had the next largest declines, all down 8-9%. Twelve states had retail sales volume increases in April, led by West Virginia (up over 3%), Louisiana (up nearly 3%), and Rhode Island (up nearly 2%).


Heating Degree Days (HDD) measure the daily variation in average temperature from a 65 degree Fahrenheit baseline, chosen as a proxy for minimum heating or cooling energy demand. HDDs rose in 32 states and the District of Columbia in April, largely across the South and eastern half of the country. Fourteen states had HDD declines from last year, mostly in the western US. The largest declines were found in the Pacific Northwest, where Washington, Oregon, and Idaho had their second-warmest April on record. This warm weather had a large impact on hydrological conditions across the West. Snowpack levels diminished considerably, sharply increasing water flows. Though positive for hydro generation during the month (total hydro generation increased from 12.94 terawatthours in April 2015 to 17.91 terawatthours in April 2016 across the West), it will also have the effect of decreasing hydro generation potential in the coming months as snowpack levels are lower to nonexistent.

 

Resource Use: April 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



map showing electricity regions

Net generation in the United States decreased by only 0.3% from the previous April. This occurred because the country, as a whole, experienced very similar temperatures in both April 2015 and April 2016. At the regional-level, the largest percent change in generation compared to the previous April occurred in Florida. In April 2015, Florida experienced record warm temperatures, whereas in April 2016, the state only experienced above average temperatures. This led to a year-over-year decrease of 3.6% in electricity generation for Florida.

Electricity generation from coal decreased in all regions of the country except for the Northeast and MidAtlantic. However, like last month, the change in natural gas generation from the previous year was more mixed. Florida, Texas, and the West all saw year-over-year decreases in natural gas generation, whereas the Northeast, MidAtlantic, Southeast, and Central regions all observed increases in natural gas generation compared to the previous April. All regions of the country, except for the Northeast, saw an increase in nuclear generation. The Northeast saw a 24.4% drop in nuclear generation compared to April 2015 because the Indian Point 2 nuclear plant in New York was offline for refueling and maintenance.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in April 2015 and April 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 April 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 April 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 outlier was in the Northeast, where the very small share of coal consumption increased slightly at the expense of natural gas compared to the previous April.

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 from the previous month, going from $1.76/MMBtu in March 2016 to $1.96/MMBtu in April 2016. The natural gas price for New York City (Transco Zone 6 NY) also increased from the previous month, going from $1.36/MMBtu in March 2016 to $1.61/MMBtu in April 2016.

The New York Harbor residual oil price increased from the previous month, going from $5.35/MMBtu in March 2016 to $5.69/MMBtu in April 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 sixteenth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. The spread between the two prices decreased significantly in April 2016, mainly due to the increase in the price of natural gas at Henry Hub. The price of natural gas at New York City on a $/MWh basis was below the price of Central Appalachian coal for a second consecutive month, albeit 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: April 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 prices



Selected wholesale electricity pricing locations

Wholesale electricity and natural gas prices varied widely across the country in April. Prices peaked at much higher levels in New England than at any other location, as natural gas prices of $5.75/MMBtu led to electricity prices just over $50/MWh. By comparison, the highest daily natural gas price anywhere else in the country was only $2.13/MMBtu and the highest electricity price anywhere else was $43/MWh. The lowest wholesale electricity and natural gas prices in the country were both found in the Northwest. Natural gas prices bottomed out at $1.06/MMBtu at Sumas and electricity prices ranged from only $4-$16/MWh at Mid-C, influenced by both the low natural gas prices and robust hydro generation during the month.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand in April remained near the low end of the 12-month range at all locations across the country. Annual lows were set in New England (ISONE), New York State (NYISO), Southern Company, and Texas (ERCOT) and nearly set in the Mid-Atlantic (PJM), the Midwest (MISO), and Progress Florida. Daily peak maximums remained largely between 60-70% of all-time peak levels, with Progress Florida and Texas (ERCOT) the only regions exceeding 70% of all-time peaks, though both regions were far short of 12-month peak levels.

 

Electric Power Sector Coal Stocks: April 2016

 



In April, U.S. coal stockpiles increased to 196 million tons, up 1% from the previous month. As a whole, U.S. coal stockpiles are at very 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 97 days of burn in March to 91 days of forward-looking days of burn in April. For subbituminous units largely located in the western United States, the average number of days of burn decreased, going from 102 days in March to 93 days in April.

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

  April 2016   April 2015   March 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
Northeast Bituminous 7,641 117   6,061 81 26.1% 7,165 111 6.7%
  Subbituminous 171 184   799 262 -78.6% 171 208 0.0%
South Bituminous 37,654 89   33,819 76 11.3% 36,811 97 2.3%
  Subbituminous 7,838 86   6,927 79 13.1% 7,951 95 -1.4%
Midwest Bituminous 18,365 95   14,820 74 23.9% 18,005 100 2.0%
  Subbituminous 46,805 86   38,488 70 21.6% 46,914 94 -0.2%
West Bituminous 5,587 76   5,341 72 4.6% 4,907 76 13.9%
  Subbituminous 41,393 103   34,743 86 19.1% 42,090 114 -1.7%
U.S. Total Bituminous 69,247 91   60,041 76 15.3% 66,888 97 3.5%
  Subbituminous 96,207 93   80,957 77 18.8% 97,126 102 -0.9%

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.

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 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.