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Electricity Monthly Update

With Data for February 2016  |  Release Date: April 28, 2016  |  Next Release Date: May 25, 2016

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Highlights: February 2016

Key Indicators

  February 2016 % Change from February 2015
Total Net Generation
(Thousand MWh)
314,079 -6.4%
Residential Retail Price
(cents/kWh)
12.15 -1.1%
Retail Sales
(Thousand MWh)
294,194 -3.4%
Heating Degree-Days 659 -28.0%
Natural Gas Price, Henry Hub
($/MMBtu)
2.00 -31.3%
Natural Gas Consumption
(Mcf)
722,190 6.6%
Coal Consumption
(Thousand Tons)
50,649 -24.5%
Coal Stocks
(Thousand Tons)
188,975 26.2%
Nuclear Generation
(Thousand MWh)
65,638 3.4%



Non-powered dams represent a significant source of additional hydroelectric capacity

EIA expects 1,083 megawatts (MW) of hydroelectric capacity installed between 2015 and 2019 in the United States. Of that hydroelectric capacity, 422 MW of the capacity additions belong to dams that did not previously have electric generating units, commonly referred to as non-powered dams (NPDs). The image below shows the Cannelton Hydroelectric Project on the Ohio River in Kentucky, which is adding 88 MW of generating capacity to an NPD this year.

Source: Google Maps

Although the capacity gain from such hydro installations is modest on a national scale, relative to the gains of other renewable energy sources (such as solar and wind), these recent NPD developments illustrate how another potentially significant renewable resource can provide significant state-level gains. As a result of NPD capacity additions, Kentucky and West Virginia will increase their hydroelectric capacities by roughly 32% and 15% respectively this year. Kentucky will increase its overall renewable capacity by 30% by the end of 2016.

Although electric generating units have been installed at NPDs throughout the country, one water source accounts for much of this activity. Of all the new and planned NPD capacity additions, 74% of them occur along the Ohio River.

Source: U.S. Energy Information Administration, Form EIA-860 Annual Electric Generator Report

The U.S. Department of Energy (DOE) estimated that as of 2012, NPDs had the potential to add 12 gigawatts (GW) of additional generating capacity. Since then, four NPD projects to increase generating capacity on the Ohio River are underway: Cannelton Hydroelectric Project, Meldahl Hydroelectric Project, Smithland Hydroelectric Project, and Willow Island Hydroelectric Project. Once these projects are complete, the total hydroelectric capacity along the Ohio River will increase 130% from 313 MW to 554 MW.

In addition to the four Ohio River projects scheduled for completion at the end of 2016, the locks and dams along the Ohio River provide the largest river resource for additional NPD development. In addition to the four projects scheduled for completion this year, the U.S. DOE identified seven additional Ohio River projects with the potential to collectively generate over 13 million megawatthours (MWh) each year, far more than the 1.5 million MWh generation produced by Ohio River hydro facilities in 2014.


Principal Contributor:

Alexander Mey
(Alexander.Mey@eia.gov)

 

End Use: February 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 35 states in February. The largest declines were found in New York (down 17%), Rhode Island (down 16%), and Hawaii (down 15%). Though down significantly, this was the first month in over a year that Hawaii was not the state with the largest year-over-year decline, as lower year-over-year comparisons are starting to take effect. Fifteen states and the District of Columbia increased compared to last year, led by West Virginia (up 14%), the District of Columbia (up 6%), and Washington State (up nearly 6%).

Average revenues per kilowatthour and retail sales volumes were both significantly lower in total and across all sectors in February when compared to last year. Average revenues per kilowatthour were 9.99 cents in February, down 3.8% from last year. Retail sales volumes totaled 294,194 gigawatthours (GWh), down 3.4% from last year. The Residential sector, the most sensitive to weather, was down 6.4% from last year, as what turned out to be the warmest winter on record depressed heating demand.

Retail sales



State retail sales volumes were mostly down in February compared to last year. Thirty-six states had lower retail sales volumes, led by Connecticut, Rhode Island (both down 12%), and West Virginia (down 11%). Florida, Maine, and the District of Columbia were the only areas east of the Mississippi River with higher retail sales volumes than last February. Fourteen states and the District of Columbia had higher retail sales volumes than last February, led by Arizona (up 10%), Nevada (up 8%), and Utah (up 6%).


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 fell in 43 states and the District of Columbia in February, with only eight states in the western US recording higher HDDs than one year ago. The largest HDD decreases were found in Texas (down 41%), Oklahoma (down 38%), and Arkansas (down 37%). In total, 31 states had decreases larger than 25% for the month. The few increases in HDDs were found in the extreme western US. Utah recorded the largest increase, up 26%, followed up Idaho (up 13%), and Nevada (up 12%).

 

Resource Use: February 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

In February 2016, net generation in the United States decreased 6.4% from the previous year. This occurred because the country experienced extremely warm temperatures in February 2016, leading to a decreased demand for electricity generation used for residential heating. At the regional-level, only the West saw a noticeable increase in electricity generation (1.2%) compared to last February, caused by the record warm temperatures experienced last February. During this February, the West experienced temperatures that led to a slight uptick in heating demand compared to the previous year and thus, the region observed a slight increase in electricity generation.

Electricity generation from coal continued the trend of year-over-year decreases in all regions of the country. For the second consecutive month, natural gas generation increased in all regions of the country, except for in Texas, where electricity generation decreased due a decline in residential heating due to weather conditions. Nuclear generation increased 3.4% compared to February 2015, with all regions of the country seeing a year-over-year increase in nuclear generation. Electricity generation from other renewables saw an increase in all regions of the country, with the largest percentage increase occurring in Texas (54.3%) due to many new wind farms coming online since last year.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in February 2015 and February 2016 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 February mirrored the increases in electricity generation from natural gas over the same period, including Texas, where natural gas consumption decreased compared to the prior February.

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 February 2016, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption compared to the previous year. In the Northeast, natural gas also increased its share at the expense of other fossil fuels, which saw a larger than usual share of fuel consumption during the previous February.

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 from the previous month, going from $2.35/MMBtu in January 2016 to $2.00/MMBtu in February 2016. The natural gas price for New York City (Transco Zone 6 NY) also decreased from the previous month, going from $3.76/MMBtu in January 2016 to $3.00/MMBtu in February 2016.

After three consecutive month-over-month decreases, the New York Harbor residual oil price increased from the previous month, going from $5.14/MMBtu in January 2016 to $5.28/MMBtu in February 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 fourteenth 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 increased in February 2016, mainly due to the decrease in the price of natural gas at Henry Hub. The price of natural gas at New York City on a $/MWh basis was above the price of Central Appalachian coal for the second consecutive month, however, the spread between the two prices decreased due to the decrease 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: February 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 were much lower this February compared to the last several years, particularly in the Northeast. A combination of warmer-than-normal temperatures, additional pipeline infrastructure, and the generally well-supplied and low-priced natural gas environment led to the much lower prices. In the electricity market, peak prices for the month reached only $53/MWh in New England (ISONE), down from $211/MWh last year and $236/MWh two years ago. Peak prices in New York City (NYISO) reached only $62/MWh this year, down from $223/MWh last year and $227/MWh two years ago. In the Mid-Atlantic (PJM), peak prices reached only $46/MWh this year, down from $279/MWh last year and $208/MWh two years ago. And in the Midwest (MISO), peak prices reached only $30/MWh this year, down from $64/MWh last year and $111/MWh two years ago. Prices remained below $32/MWh at all other selected trading points during the month.

Wholesale natural gas prices experienced similar price declines. Peak prices for the month reached only $7.88/MMBtu in New England (Algonquin), down from $29.25/MMBtu last year and $31.50/MMBtu two years ago. Peak prices in New York City (Transco Z6 NY) reached only $7.62/MMBtu this year, down from $35.37/MMBtu last year and $24.29/MMBtu two years ago. In the Mid-Atlantic (Tetco M-3), peak prices reached only $4.67/MMBtu this year, down from $20.97/MMBtu last year and $21.10/MMBtu two years ago. And in the Midwest, peak prices reached only $2.29/MMBtu this year, down from $10.20/MMBtu last year and $22.81/MMBtu two years ago. Peak prices remained below $2.50/MMBtu at the other selected trading points around the country.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand this February reflected a continuation of warmer-than-normal weather in what would become the warmest winter on record for the lower-48. There was a lack of extremely high demand days during the month, while all ten regions recorded days close to the low end of the range for the last 12 months. Last February, 12-month high peak demand days were set in the Mid-Atlantic (PJM) and in Progress Florida. The year before that, a 12-month high was set in the Northwest (Bonneville Power Administration). None came close to new 12-month highs this February. By region, peak demand days were mixed compared to last February, with five recording higher daily peaks and five lower. New England, Southern Company, Progress Florida, Tucson Electric, and California had higher daily peak demand while New York State, Mid-Atlantic, Midwest, Texas, and Bonneville Power Administration had daily peaks lower than last year.

 

Electric Power Sector Coal Stocks: February 2016

 



In February, U.S. coal stockpiles remained relatively flat compared to the previous month, deviating from the normal seasonal pattern where stockpiles decrease during the winter months. The departure from the winter draw-down in coal stocks occurred because of the extremely warm temperatures experienced throughout the country in February 2016 and also becaue coal continues to lose 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 94 days of burn in January to 99 days of forward-looking days of burn in February. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 101 days in January to 105 days in February. The 99 days of burn for bituminous units and 105 days of burn for subbituminous units are the highest level of days reached since this metric was calculated beginning in January 2010.

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

  February 2016   February 2015   January 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 7,725 113   5,982 85 29.1% 7,963 100 -3.0%
  Subbituminous 545 303   747 260 -27.1% 652 220 -16.5%
South Bituminous 34,970 99   30,211 81 15.8% 35,788 97 -2.3%
  Subbituminous 7,689 99   5,942 80 29.4% 7,792 98 -1.3%
Midwest Bituminous 17,391 99   13,392 74 29.9% 17,447 91 -0.3%
  Subbituminous 46,504 95   32,575 64 42.8% 46,617 87 -0.2%
West Bituminous 5,313 85   4,746 74 11.9% 4,852 78 9.5%
  Subbituminous 42,051 121   30,848 91 36.3% 40,971 121 2.6%
U.S. Total Bituminous 65,400 99   54,331 79 20.4% 66,051 94 -1.0%
  Subbituminous 96,789 105   70,112 76 38.0% 96,032 101 0.8%

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.