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Electricity Monthly Update

With Data for February 2017  |  Release Date: April 25, 2017  |  Next Release Date: May 24, 2017

Previous Issues

Highlights: February 2017

  • Wholesale electricity market prices and demand were generally low given extremely mild February weather across most of the country.
  • The natural gas prices at Henry Hub and New York City were below the price of Central Appalachian coal on a $/MWh basis for the first time since November 2016.
  • Net generation in the United States decreased 8.1% from February 2016 due to the extremely mild February temperatures.

Key indicators

  February 2017 % change from February 2016
Total net generation
(thousand MWh)
288,424 -8.1%
Residential retail price
(cents/kWh)
12.82 5.6%
Retail sales
(thousand MWh)
272,996 -6.9%
Heating degree-days 549 -14.9%
Natural gas price, Henry Hub
($/MMBtu)
2.90 45.0%
Natural gas consumption
(Mcf)
584,745 -18.4%
Coal consumption
(thousand tons)
48,155 -4.8%
Coal stocks
(thousand tons)
161,985 -13.6%
Nuclear generation
(thousand MWh)
64,053 -2.4%



In 2016, natural gas exceeds coal for the first time in the U.S. electricity generation mix

In 2016, electricity generated from natural gas accounted for the largest share (33.8%) of total U.S. generation, surpassing coal's share (30.4%) for the first time. The changes in generation fuel shares in 2016 reflect longer-term trends in the electricity supply market.

Between 2011 and 2016, coal and natural gas combined accounted for 66% of total U.S. electricity generation. However, the relative shares of output from these two fuels has shifted, with coal's share declining from 42.3% in 2011 to 30.4% in 2016. Over the same period, the natural gas share increased from 24.7% to 33.8%.

Natural gas units generated 1,013,689 gigawatt hours (GWh) in 2011 and 1,380,295 GWh in 2016, which was an all-time high for natural gas generation and a 36% increase from the 2011 level. Coal units generated 1,733,430 GWh in 2011 and 1,240,108 GWh in 2016, a decrease of 28% compared to the 2011 level.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report
Note: Data for 2016 are preliminary.

Changes in the generation fuel mix are generally the result of relative fuel prices and generators' expectations regarding future costs of fuels, emission control, and operation and maintenance (O&M). Recent trends in generating units include retirements of older coal-fired generators and increased investment in natural gas and renewable capacity in response to market conditions and the implementation of recent environmental regulations.

In addition to the shifting generation shares among fossil fuels, the share of generation from non-hydro renewables (wind, biomass, solar and geothermal) in 2016 increased to 8.4%, surpassing the 6.5% share from conventional hydroelectric renewable generation.

Renewable energy sources include conventional hydroelectric power and non-hydroelectric sources (wind, geothermal, biomass, and solar). Hydro power has traditionally been the dominant source of renewable power generation, accounting for 7.8% U.S. electricity generation, and 62.2% of all renewable generation in 2011. Non-hydro renewable sources provided 5.4% of U.S. electricity generation in 2011. Over the past five years, hydro power generation has fallen to 6.5% of U.S. electricity generation, while non-hydro renewables generation increased to 8.4%. Non-hydro generation in 2016 accounted for 56.4% of all renewable generation.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report
Note: Data for 2016 are preliminary.

Generation from non-hydro sources, particularly wind and solar, has expanded as capital costs and incremental costs of generation have declined over time. In addition, policies such as the Federal Production Tax Credit (PTC), the Investment Tax Credit (ITC), and state-level renewable portfolio standards (RPS) which aim to increase generation from renewable sources, have pushed the development of renewables as a whole, and non-hydro renewables in particular.

Non-hydro renewables generated 343,616 GWh in 2016, while conventional hydroelectric generated 265,829 GWh. The largest increases in generation from non-hydro renewables in 2016 were from wind and solar power.


Principal Contributor:

Joy Liu
(Joy.Liu@eia.gov)

 

End Use: February 2017


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 9 states and the District of Columbia in February compared to last year. The largest declines were found in Virginia (down 5.5%), Connecticut (down 2.9), the District of Columbia (down 2.8), and Nevada (down 2.3%). Nebraska had no change from February last year. Forty states increased compared to last year, led by Hawaii (up almost 13%), New Mexico (up 12.7%), Oklahoma and Indiana (both up 11.3%), and Louisiana (up 10.1%).

Total average revenues per kilowatthour were up 3.3% to 10.33 cents in February compared to last year. Three sectors were up on the month, with the Residential sector leading at 5.6 %. The Industrial sector had the second-largest percent growth with 3.8 %, while the Commercial sector followed with a growth of 2.7%. The Transportation sector showed a slight decline of 0.2 % from last year. Total retail sales declined by 6.9 %, and sales decreased in all sectors. The Residential sector had the largest drop, down 12.7 percent. The Commercial, Industrial, and Transportation sectors each dropped slightly, 3.3%, 2.9 %, and 1.6%, respectively.

Retail sales



State retail sales volumes were down in 44 states and the District of Columbia in February compared to last year. The District of Columbia recorded the largest year-over-year decline, down 19.5%, West Virginia and South Carolina had the next largest declines, down 16.2% and 15.6%, respectively. Six states had retail sales volume increases in February, led by Montana (up 6.7%), Oregon (up 5.8%), and Washington (up 5.7%).


February 2017 was the second warmest February on record and the winter of 2016-2017 was the sixth warmest winter on record, according to the National Oceanic and Atmospheric Administration (NOAA). Heating degree days (HDD) were lower across most of the country, down in 37 states and the District of Columbia compared to last February. Eleven states, mostly in the West, had an increase in HDDs. The largest year-over-year increases were found in California, Washington, Arizona, and Oregon. All these states had an increase of more than 30% in HDDs from a year ago.

 

Resource Use: February 2017

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 8.1% from February 2016. The country, as a whole, experienced its second hottest February on record. This led to a decreased need for residential heating and thus, a decrease in electricity generation compared to last February. At the regional-level, all parts of the country saw a decrease in electricity generation from the previous year, with the Northeast (-10.0%), MidAtlantic (-13.0%), and Southeast (-13.6%), seeing the largest percent decreases in electricity generation compared to February 2016.

The change in electricity generation from coal was mixed throughout the country, with Florida, Texas, and the West all observing increases in coal generation, while the Northeast, MidAtlantic, Southeast, and Central regions all saw decreases in electricity generation from coal. Natural gas generation decreased in all parts of the country compared to February 2016, with the Central region seeing the largest percent decrease (-34.1%) compared to the previous February.

As a whole, nuclear generation was down 2.4% compared to February 2016, with Florida seeing the largest percent decrease (19.5%) from the previous year, due to the St. Lucie nuclear plant being offline in February 2017 for a refueling outage. Hydroelectric generation was down across most of the country compared to the previous February. However, in the Western region, increased precipitation during the month led to a nearly 21% rise in hydroelectric generation.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in February 2016 and February 2017 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption closely mirrored their respective changes in coal and natural gas generation.

The third tab presents the change in the relative share of fossil fuel consumption by fuel type on a percentage basis, calculated using equivalent energy content (Btu). This highlights changes in the relative market shares of coal, natural gas, and petroleum. In February 2017, Florida, Texas, Central, and the West saw an increase in the share of coal consumption at the expense of natural gas consumption, while the Northeast, MidAtlantic, and Southeast regions saw a decrease in coal consumption at the expense of natural gas consumption.

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. For the second consecutive month, the average price of natural gas at Henry Hub decreased from the previous month, going from $3.40/MMBtu in January 2017 to $2.90/MMBtu in February 2017. It was also the second consecutive month that the natural gas price for New York City (Transco Zone 6 NY) decreased, going from $3.94/MMBtu in January 2017 to $2.92/MMBtu in February 2017.

The New York Harbor residual oil price saw a decrease from the previous month, going from $9.70/MMBtu in January 2017 to $9.26/MMBtu in February 2017. 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 since November 2016, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. This was due to the decrease in the price of natural gas at Henry Hub from the previous month. The price of natural gas at New York City on a $/MWh basis was also below the price of Central Appalachian coal for the first time since November 2016, also a result of the natural gas price at New York City decreasing from the previous month.

The conversion shown in this chart is done for illustrative purposes only. The competition between coal and natural gas to produce electricity is more complex. It involves delivered prices and emission costs, the terms of fuel supply contracts, and the workings of fuel markets.

 

Regional Wholesale Markets: February 2017

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 natural gas and electricity prices remained on the low (electricity) to middle (natural gas) part of the 12-month range during the month as the country enjoyed its second warmest February on record. New England (ISONE) was the only electricity hub to exceed $50/MWh, hitting $51/MWh on February 10 during the only real cold-snap the Northeast experienced during the month. Temperatures fell to a low of 11 degrees Fahrenheit in Boston on February 9 and 10, cold but far from the lows reached on many winter days in this region. Not surprising, natural gas prices also hit a high for the month during this cold weather, reaching $6.25/MMBtu on February 9 in New England (Algonquin).

During the same cold weather period, wholesale electricity ($49/MWh) and natural gas ($4.11/MMBtu) prices hit highs for the month in New York City. Wholesale electricity prices remained below $40/MWh at the other trading hubs across the country and even approached 12-month lows in the Mid-Atlantic (PJM), Midwest (MISO), and the Southwest (Palo Verde). Outside of the Northeast, wholesale natural gas prices remained in a band between $2.00-$3.50/MMBtu during the month.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand reflected very warm February weather with daily peak demand on the lower end of the 12-month range for nearly all electricity systems. Sixteen states from Texas to New York recorded their warmest February on record and nearly every state in the continental US had well above-normal average temperatures for the month. This resulted in daily peak demand below 70% of all-time peak on all systems except Bonneville Power Administration (BPA) in the Northwest, and a new 12-month low daily peak demand in Progress Florida, where peak demand reached just 5,388 megawatts (MW) on February 18.

The higher daily peak demand levels in BPA are no surprise given that it was the one region in the country where temperatures were near average (Oregon) or below average (Washington). Daily electricity system peak demand in BPA peaked at 9,256 MW on February 3, 80% of that system's all-time peak, though this was far below January's daily peak demand of nearly 11,000 MW.

 

Electric Power Sector Coal Stocks: February 2017

 



In February, U.S. coal stockpiles increased to 162 million tons, up 3% from the previous month. This increase in total coal stockpiles occurred because the country experienced extremely warm temperatures in February 2017, which led to a decreased need for electricity generation during the month.

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 90 days of burn in January to 100 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 from 99 days in January to 104 days in February.

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

  February 2017   February 2016   January 2017  
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 5,229 92   7,729 113 -32.4% 5,177 74 1.0%
  Subbituminous 159 168   545 303 -70.7% 96 30 66.7%
South Bituminous 31,517 100   34,500 98 -8.6% 29,594 90 6.5%
  Subbituminous 6,144 88   7,689 99 -20.1% 5,760 76 6.7%
Midwest Bituminous 15,017 100   17,391 99 -13.7% 15,035 91 -0.1%
  Subbituminous 43,181 104   46,504 95 -7.1% 41,860 96 3.2%
West Bituminous 5,732 103   5,372 86 6.7% 5,583 103 2.7%
  Subbituminous 30,470 108   42,051 121 -27.5% 29,650 107 2.8%
U.S. Total Bituminous 57,495 100   64,992 99 -11.5% 55,390 90 3.8%
  Subbituminous 79,955 104   96,789 105 -17.4% 77,366 99 3.3%

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.