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Electricity Monthly Update

With Data for November 2016  |  Release Date: Jan. 26, 2017  |  Next Release Date: Feb. 24, 2017

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Highlights: November 2016

Key Indicators

  November 2016 % Change from November 2015
Total Net Generation
(Thousand MWh)
297,422 -1.1%
Residential Retail Price
(cents/kWh)
12.75 0.3%
Retail Sales
(Thousand MWh)
272,932 -1.1%
Heating Degree-Days 418 -5.6%
Natural Gas Price, Henry Hub
($/MMBtu)
2.60 21.0%
Natural Gas Consumption
(Mcf)
700,215 -8.7%
Coal Consumption
(Thousand Tons)
48,126 -1.7%
Coal Stocks
(Thousand Tons)
172,139 -8.7%
Nuclear Generation
(Thousand MWh)
65,179 8.2%



The output range of large electric coal-fired steam turbines varies widely

Large coal-fired steam turbine generators vary widely in their range of output. To follow varying demand on electric systems over time, the collective output of generators must be able to increase and decrease rapidly. The recent significant increase in generation from renewable resources, whose output varies depending on resource availability, has added another source of variation that thermal generators need to be able to respond to. As a result, the operating ranges of these generators are becoming more important.

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: Large means summer capacity greater than 100 megawatts (MW)

The chart above shows the output range of an important class of generators-large (>100 MW) coal-fired steam turbines--which represents about a quarter of the U.S. electric generating fleet. Recently, more of these generating units have taken on the role of marginal generators as a result of competition from natural gas-fired combined-cycle units. This means that the coal units are more often called on to increase and decrease their output.

The operating range of a generator is defined as the span between its summer peak capacity and its minimum load. Although the maximum output of a generator is typically set by thermal limits, the minimum value is often determined by technical factors such as mechanical and electrical instabilities, and by business considerations such as the higher operating costs associated with running a unit at lower levels of output. Anticipating the increasing importance of unit output ranges, EIA began collecting minimum load in 2013 in addition to peak capacity.

A key implication behind the minimum load of a generator is the ability to keep a unit operating when demand for power from that generator drops. If demand falls below the minimum load, the unit must shut down. For most conventional generators, repeated start-ups create significant maintenance challenges that increase operating costs and decrease equipment life. Large steam turbine units that have historically operated as baseload generators are particularly susceptible to cycling problems.

The ability of these systems to operate more flexibly, perhaps by increasing their operating range by lowering their minimum load, may be an important competitive advantage as generation from renewable resources increases.


Principal Contributor:

Glenn McGrath
(Glenn.McGrath@eia.gov)

 

End Use: November 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 19 states and the District of Columbia in November compared to last year. The largest declines were found in Nevada (down 10.9%) and Oklahoma (down 5.9%). Thirty-one states increased compared to last year, led by Minnesota (up 9%), North Dakota (up 8.4%), and Indiana (up 8.3%).

Total average revenues per kilowatthour were up 0.5% to 10.10 cents in November compared to last year. Two sectors were down on the month, the Transportation sector with a 6.1% drop and the Commercial sector with a 0.5% drop. The Residential and Industrial sectors showed slight gains in average revenue per kilowatthour from last year, rising 0.3% and 0.5%, respectively. Retail sales were down overall by 1.1%, to 272,932 gigawatthours (GWh). The Industrial and Transportation sectors showed declines of 4.3% and 2.0%, respectively, while the Residential and Commercial sectors rose slightly by 0.1% and 0.3%, respectively.

Retail sales



State retail sales volumes were down in 33 states and the District of Columbia in November compared to last year. Florida recorded the largest year-over-year decline, down 8.9%, Missouri and Oregon had the next largest declines, down 7.6 and 7.5%, respectively. Seventeen states had retail sales volume increases in November, led by Arkansas (up 5.2%), Virginia (up 5%), and West Virginia (up 4.4%).


November 2016 was the 2nd warmest November on record according to the National Oceanic and Atmospheric Administration (NOAA). Consequently, heating degree days (HDD) were lower across most of the country, down in 27 states compared to last November. Eight states had an over 25-percent-decrease in HDDs. The largest year-over-year decrease was found in Arizona, followed by Nevada, Texas, California, Washington, Oregon, Montana, and Idaho. Twenty-two states had more HDDs than last November, with these states found in the coastal South and Mid-Atlantic. South Carolina had the largest HDD increase of any state, followed by Delaware, Maryland, North Carolina, and Virginia.

 

Resource Use: November 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 November 2016, net generation in the United States decreased 1.1% from the previous year. The country, as a whole, experienced its second warmest November on record. Normally, as the cooler autumn temperatures begin to take hold across the country each November, many states throughout the country have increased electricity generation due to the increased need for residential heating. However, because extremely warm temperatures persisted throughout the country this November, this suppressed the demand for residential heating and thus, decreased the associated electricity generation that would have been needed. This was particularly pronounced in the central and western parts of the country were heating degree days were significantly lower in November 2016 compared to November 2015.

The change in electricity generation from coal compared to the previous November was mixed throughout the country. The Southeast and Texas both saw increases in coal generation from the previous year, with the largest percent increase occurring in Texas (22.5%). Conversely, the Northeast, MidAtlantic, Central, Florida, and the West regions all saw a decrease in coal generation, with the Northeast region seeing the largest percent decrease (-73.0%) in coal generation.

The change in natural gas generation was also mixed throughout the country, with the MidAtlantic and Central regions all observing increases in natural gas generation compared to last year, while the Northeast, Southeast, Florida, Texas, and the West regions all saw decreases in natural gas generation. As a whole, nuclear generation was up 8.3% compared to the previous November, with only the Central region seeing a decrease in nuclear generation (-6.1%) due to the retirement of the Fort Calhoun nuclear plant and a refueling outage that occurred during November 2016 at Wolf Creek nuclear plant.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in November 2015 and November 2016 by region and the second tab compares natural gas consumption by region. Changes in coal and natural gas consumption closely mirrored the change in 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 November 2016, the Southeast, Florida, Texas, and West regions saw increases in the share of coal consumption at the expense of natural gas consumption, while the Northeast, MidAtlantic, and Central regions all saw natural gas consumption increase at the expense of coal 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 from the previous month, going from $3.01/MMBtu in October 2016 to $2.60/MMBtu in November 2016. The natural gas price for New York City (Transco Zone 6 NY) increased from the previous month, going from $1.23/MMBtu in October 2016 to $2.23/MMBtu in November 2016.

The New York Harbor residual oil price decreased slightly from the previous month, going from $8.41/MMBtu in October 2016 to $8.01/MMBtu in November 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. 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 and the slight increase in the price of Central Appalachian coal. The price of natural gas at New York City on a $/MWh basis was still below the price of Central Appalachian coal for a ninth consecutive month, although the spread between the two prices decreased considerably 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: November 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 prices remained near the low end of the 12-month range at all hubs across the country, as one of the warmest Novembers' on record led to lower energy demand than is typical for the month. Daily peak prices stayed below $40/MWh at all hubs except Northern California (CAISO), which reach $42 and $40 on November 29 and 30, respectively. Prices in the Northeast, which are liable to spike in the winter during times of cold weather, peaked at only $38/MWh in New England (ISONE) and $37/MWh in New York City (NYISO). The lowest daily peak price occurred in the Northwest (Mid-C) at just below $15/MWh on November 11, as Washington and Idaho experienced their warmest November on record and Oregon experienced its' second-warmest November on record.

Wholesale natural gas prices generally exhibited a U-shaped pattern in November, falling steadily during the first half of the month before bottoming out and rising the second-half of the month. For example, prices in Louisiana (Henry Hub) were $2.85/MMBtu on November 1, fell steadily to $2.06/MMBtu on November 14, before rising and ending the month at $3.02/MMBtu on November 30. This pattern was consistent at most hubs except in the Northeast, where prices remained flatter through the latter part of the month.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand was low in November due to the extremely warm weather across the country that kept winter-like energy demand at bay for another month. Three states, Washington, Idaho, and North Dakota had their warmest November on record, eleven states had their second-warmest November on record, and every other state had above- to much-above normal temperatures. Such temperatures limit the amount of heating demand and resulted in daily peak demand levels that were not that much different than demand levels in October. Twelve-month low daily peak demand levels were set in Progress Florida on November 26 and in California (CAISO) on November 24. Every system remained at 70% (Texas (ERCOT)) or below 70% of its all-time peak demand level.

 

Electric Power Sector Coal Stocks: November 2016

 



In November, U.S. coal stockpiles increased to 172 million tons, up 5.3% from the previous month. This increase in total coal stockpiles follows the normal seasonal pattern whereby coal stockpiles begin to build-up during the autumn months.

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 slightly from 86 days of burn in October to 85 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 from 87 days of burn in October to 90 days of burn in November.

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

  November 2016   November 2015   October 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 5,891 77   8,032 89 -26.6% 5,646 84 4.3%
  Subbituminous 153 63   708 147 -78.4% 136 69 11.9%
South Bituminous 30,741 82   37,019 91 -17.0% 27,996 83 9.8%
  Subbituminous 6,491 75   7,584 84 -14.4% 6,039 73 7.5%
Midwest Bituminous 17,154 90   17,550 82 -2.3% 16,909 94 1.4%
  Subbituminous 45,254 85   45,375 74 -0.3% 43,096 84 5.0%
West Bituminous 6,099 93   5,785 78 5.4% 5,859 84 4.1%
  Subbituminous 34,098 102   39,044 104 -12.7% 31,312 95 8.9%
U.S. Total Bituminous 59,885 85   68,386 87 -12.4% 56,410 86 6.2%
  Subbituminous 85,996 90   92,710 85 -7.2% 80,583 87 6.7%

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.