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Electricity Monthly Update

With Data for November 2015  |  Release Date: Jan. 26, 2015  |  Next Release Date: Feb. 26, 2016

Previous Issues

Highlights: November 2015

  • Net electricity generation decreased 5.2% compared to November 2014 as the country experienced a very warm November 2015, leading to a decreased demand for electricity generation used for residential heating.
  • Electricity system daily peak demand remained well on the low end of the annual range for almost every region as above-average temperatures caused November to resemble more of a mild shoulder month than the beginning of winter.
  • Electricity retail sales volumes declined by a significant amount in nearly every state in the eastern half of the country where abnormally mild weather lowered heating demand.

Key Indicators

  November 2015 % Change from November 2014
Total Net Generation
(Thousand MWh)
300,935 -5.2%
Residential Retail Price
(cents/kWh)
12.73 2.0%
Retail Sales
(Thousand MWh)
273,287 -4.2%
Heating Degree-Days 442 -27.7%
Natural Gas Price, Henry Hub
($/MMBtu)
2.15 -49.2%
Natural Gas Consumption
(Mcf)
765,530 20.9%
Coal Consumption
(Thousand Tons)
49,200 -23.9%
Coal Stocks
(Thousand Tons)
188,538 32.2%
Nuclear Generation
(Thousand MWh)
60,264 -7.5%



Installed wind generator tower heights and output are growing

Source: Form EIA-860, The Annual Electric Generator Report

The average height of a typical wind turbine has increased almost 70 feet since 2001. In general, wind speeds are greater and more consistent at greater heights as a result of reduced effects of surface:air friction and ground-level interferences.

The wind industry is taking advantage of those better wind conditions by using taller towers. The average hub height has increased from 196 feet in 2001 to 265 feet in 2014. During this time, average turbine capacity factors have grown from 29% in 2001 to 34% in 2014.

Source: Form EIA-860, The Annual Electric Generator Report

Improved average output per capacity depends on factors in addition to tower height, including improvements in siting practices and generator design. One important design attribute is unit size. Taller towers are able to accommodate the longer blade lengths of larger wind turbines. The average wind turbine capacity has doubled over the past 13 years, moving from approximately 1 megawatt (MW) in 2001 to 2 MW in 2014.


Principal Contributor:

Glenn McGrath
(Glenn.McGrath@eia.gov)

 

End Use: November 2015


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 increased in 29 states and the District of Columbia in November compared to last year. The largest increase occurred in Rhode Island, up nearly 12%, followed by West Virginia, up 10%, and Washington, up 8%. Twenty-one states decreased relative to last November, led once again by Hawaii, down 25%, Georgia, down 10%, and Texas, down 8%. This marks the eleventh straight month that Hawaii has been the state with the largest year-over-year declines, as its bulk power system is largely fueled by petroleum and the state has benefitted from the huge declines in world oil prices over the past year.

Total average revenues per kilowatthour were 10.11 cents in November, down 0.2% from last year. Retail sales volumes totaled 273,287 GWh, down 4.2% from last year. Average revenue/sales were up in the Residential sector and down in the Commercial, Industrial, and Transportation sectors. Retail sales volumes were down in all sectors compared to one year ago.

Retail sales



State retail sales volumes were very reflective of weather patterns in November. Volumes declined, and by a significant amount, in nearly every state in the eastern half of the country where abnormally mild weather lowered heating demand. West Virginia declined the most, down over 15%, and four states (Kentucky, Virginia, Indiana, and Missouri) were down 10-15% from last year. The only area of the country with cooler-than-normal weather, the far West, was also the only area of the country (and Florida, a special case) with increased retail sales volumes. Besides Florida, California had the largest year-over-year increase, up 6%, followed by Hawaii and Nevada, both up 5%, and Washington, up 3%. Florida actually had the largest increase of any state, up 12.5%, where one of the hottest Novembers on record had residents turning up their air conditioners very late in the year.


All states east of the Rockies saw Heating Degree Day (HDD) levels decrease compared to the previous November. Five states near the Gulf of Mexico were down more than 50% from last year, led by Florida (down 90%), Louisiana (down 62%), and Mississippi (down 55%). States in New England had HDDs that were down 15-25%, while every other state east of the Rockies were down 25-50% compared to last year. On the contrary, every state in the continental U.S. west of the Rockies had higher levels of HDDs compared to last year, led by California (up 66%), Arizona (up 53%), and Nevada (up 31%).

 

Resource Use: November 2015

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 5.2% compared to the previous November. This large decrease in generation occurred because the country experienced a very warm November 2015, leading to a decreased demand for electricity generation used for residential heating. Furthermore, the country experienced a very cold November 2014, which further aided in the large decrease in electricity generation when November 2015 is compared to November 2014. At the region-level, the only region of the country that saw an increase in electricity generation compared to the previous year was Florida, where above average temperatures actually led to an increase in electricity generation as demand for residential cooling increased.

Electricity generation from coal decreased in all regions of the country compared to November 2014, while electricity generation from natural gas increased in all regions of the country over the same time period. This overall decrease in coal generation and increase in natural gas generation throughout the country has been observed over the past several months, as low natural gas prices have contributed to the increased reliance on natural gas for electricity generation.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in November 2014 and November 2015 by region and shows that, like electricity generation from coal, coal consumption decreased in all regions of the country.

The second tab compares natural gas consumption by region and shows that increases in natural gas consumption from the previous November mirrored the increases 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 November 2015, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption compared to the previous year.

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 considerably from the previous month, going from $2.37/MMBtu in October 2015 to $2.15/MMBtu in November 2015. The natural gas price for New York City (Transco Zone 6 NY) also saw a decrease from the previous month, going from $2.21/MMBtu in October 2015 to $1.86/MMBtu in November 2015.

The New York Harbor residual oil price decreased from the previous month, going from $7.62/MMBtu in October 2015 to $7.40/MMBtu in November 2015. 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 eleventh 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 widened considerably compared to the previous month, due to the large drop in the price of natural gas at Henry Hub. The spread between the New York City gas price and the price of Central Appalachian coal increased as well, albeit not as drastically, due mainly to the decrease in the natural gas price of 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: November 2015

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

Daily on-peak wholesale electricity prices fell on the lower end of the yearly range in November as mild weather covered much of the country and natural gas prices remained extremely low. Prices were highest in New England (ISONE) at $53/MWh, followed by $40/MWh in the Mid-Atlantic (PJM), and $34/MWh in New York City (NYISO). As is often the case, the lowest price was found in the Northwest (Mid-C) where the daily peak price reached only $16.50/MWh in mid-November. Wholesale natural gas prices remained very low during the month. Outside of New England (Algonquin), which peaked at $4.80/MMBtu on November 2, the highest natural gas prices at any of the other nine trading hubs was only $2.88/MMBtu.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand remained well on the low end of the annual range for every region besides the Northwest (Bonneville Power Administration, or BPA), as above-average temperatures for most of the country caused November to resemble more of a mild shoulder month than the beginning of winter. California (CAISO) actually set a new 12-month low daily peak demand in November, with every other region coming close to new 12-month lows during the month. BPA set a new 12-month daily peak demand of 9,569 MW on November 30, though this was well short of BPA's all-time maximum peak demand of nearly 11,561 MW. Cold weather descended upon the Northwest during the last week in November, pushing temperatures well below normal and increasing electricity demand.

 

Electric Power Sector Coal Stocks: November 2015

 



In November, U.S. coal stockpiles increased to 189 million tons, up 7% from the previous month. This increase in October-to-November coal stockpiles follows the normal seasonal pattern whereby coal stockpiles get built up during the fall months. Coal stockpiles are still at relatively high levels due to a loss in market share to natural gas in all 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 increased from 87 days of burn in October to 88 days of forward-looking days of burn in November. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 80 days in October to 85 days in November. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn decreased slightly from 5.5% in October to 4.7% in November.

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

  November 2015   November 2014   October 2015  
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 8,032 89   7,072 81 13.6% 7,509 95 7.0%
  Subbituminous 708 147   427 83 65.8% 731 174 -3.2%
South Bituminous 37,314 92   33,814 84 10.3% 35,209 90 6.0%
  Subbituminous 7,584 84   5,497 60 38.0% 6,942 76 9.2%
Midwest Bituminous 17,607 83   13,715 65 28.4% 16,361 82 7.6%
  Subbituminous 45,384 74   29,923 47 51.7% 41,636 71 9.0%
West Bituminous 5,789 78   4,639 60 24.8% 5,628 75 2.9%
  Subbituminous 38,774 103   22,271 56 74.1% 34,805 94 11.4%
U.S. Total Bituminous 68,742 88   59,241 76 16.0% 64,708 87 6.2%
  Subbituminous 92,450 85   58,117 52 59.1% 84,115 80 9.9%

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.