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Electricity Monthly Update

With Data for November 2017  |  Release Date: Jan. 24, 2018  |  Next Release Date: Feb. 26, 2018

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Highlights: November 2017

  • Wholesale electricity prices peaked at roughly $60/MWh in California, less than half the levels seen during the previous three months when scorching heat enveloped the state.
  • The highest wholesale natural gas prices in the country were found at Algonquin Citygates near Boston in November 2017. This was due to cold temperatures that occurred in the region during the middle of the month.
  • The spread between the New York City natural gas price and Central Appalachian coal price narrowed significantly from the previous month.

Key indicators




Utility-scale electric batteries differ widely on their discharge duration

Batteries can serve a range of applications that require different performance characteristics. One attribute that is particularly important to the applications that a battery is suited for is its discharge duration. The duration of a battery is the ratio of its energy storage, measured in megawatt-hours (MWh), to its capacity, measured in megawatts (MW). The number of utility-scale batteries installed in the United States at the end of 2016 by discharge duration is shown below.

The most frequent battery unit discharge duration is one hour. There are nearly equal numbers of batteries that discharge their full energy in 1 hour or less as those that do so in 1 hour or more. Batteries that provide their output quickly are well suited for utility services such as maintaining the real-time supply-demand balance in electricity systems. Batteries with multi-hour discharge durations can eliminate the need to start up peaking generators at times of peak electricity demand. Currently, only about 50 MW of the 552 MW total utility-scale battery capacity have durations of four hours or longer.

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

Principal Contributor:

Glenn McGrath
(Glenn.McGrath@eia.gov)

 

End Use: November 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 13 states in November compared to last year. The largest declines were found in Maine (down almost 18%), Maryland (down 4%), and Missouri (down 2%). Thirty six states and the District of Columbia increased revenue per kilowatthour compared to last year, led by Nevada (up almost 15%), Oklahoma, and Florida (both up 11).


Total average revenues per kilowatthour were up 2.8% to 10.38 cents in November compared to last year. All four sectors rose slightly, with the Transportation sector rising the most at 2.9%. The Residential, Commercial, and Industrial sectors each rose 2.0%, 2.2%, and 2.0%, respectively. Retail sales were up slightly by 0.6% for the month. The Residential sector rose the highest of the four sectors, growing by 4.6%. The Transportation sector followed with a growth of 1.1%. The Industrial and Commercial sectors each dropped from their levels last November, by 2.9% and 0.3%, respectively.

Retail sales



State retail sales volumes were down in 15 states in November compared to last year. Texas showed the largest year-over-year decline, down 4.1%. Tennessee and Arizona had the next largest declines, down 3.4% and 3.3%, respectively. Thirty five states and the District of Columbia had retail sales volume increases in November, led by Massachusetts (up 17.9%) and Maine (up 8.7%).


Heating Degree Days (HDD) were down in 6 states compared to last November. The largest decreases occurred in the Southwest, where Arizona dropped by 122 HDDs, an over 64% decrease. Likewise, New Mexico went down by 124 HDDs, a 23% decline. The third state in the top 3 was Florida. It had 20 less HDDs in November 2017, a 45% decline. Rounding out the top 5 states with lower HDDs were California and Nevada, both down almost 10% and 9%, respectively. Forty three states and the District of Columbia had increases in HDDs in November. The top seven states, which each had an over 30% increase in HDDs, were all located in the upper Mid-West: North Dakota (up 50.5%), Minnesota (up 44.6%), Iowa and Wisconsin (both up 39%), Illinois (up 34%), Montana (up 31%), and Michigan (up 30%).

 

Resource Use: November 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 increased by 3.3% in November 2017 compared to the previous year. This year-over-year increase in electricity generation occurred primarily because the country experienced a cooler November in 2017 than it did the previous year. This led to an increased need for residential customer heating compared to November 2016 and thus, an increased need for electricity generation. At the regional-level, all regions of the country, except the Western and MidAtlantic regions, saw an increase in electricity generation from the previous November.

The Southeast, Florida, MidAtlantic, and Northeast all saw a decrease in electricity generation from coal compared to the previous year, while the West, Texas, and Central all saw an increase in coal generation. Texas, Central, MidAtlantic, and Northeast all saw a decrease in electricity generation from natural gas compared to November 2016, with the Central region seeing the largest decrease (1,591 gigawatthours). The West, Southeast, and Florida all saw an increase in natural gas generation, with Florida seeing the largest increase (996 gigawatthours).

Net generation from nuclear was up 2.2% compared to the previous year. Electricity generation from other renewable sources increased in every region, mainly driven by the increase in production from newly-built wind and solar power plants that came online during 2017.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in November 2016 and November 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 November 2017, the West, Texas, and Central saw an increase in the share of coal at the expense of natural gas. Conversely over the same period, the Southeast, Florida, MidAtlantic, and Northeast all saw an increase in the share of natural gas at the expense of coal.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were similar to the changes seen in total coal and natural gas net generation in each region.

Fossil fuel prices




To gain some insight into the changing pattern of consumption of fossil fuels over the past year, we look at relative monthly average fuel prices. A common way to compare fuel prices is on an equivalent $/MMBtu basis as shown in the chart above. The average price of natural gas at Henry Hub increased from the previous month, going from $2.95/MMBtu in October 2017 to $3.07/MMBtu in November 2017. The natural gas price for New York City (Transco Zone 6 NY) also increased from the previous month, going from $2.42/MMBtu in October 2017 to $3.00/MMBtu in November 2017. For the third consecutive month, the average price of Central Appalachian coal saw an increase from the previous month, going from $2.40/MMBtu in October 2017 to $2.54/MMBtu in November 2017.

For the fifth consecutive month, the New York Harbor residual oil price saw an increase from the previous month, going from $9.25/MMBtu in October 2017 to $10.31/MMBtu in November 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. The price of natural gas at Henry Hub ($24.63/MWh) and New York City ($24.05/MWh) were below the price of Central Appalachian coal ($27.47/MWh) on a $/MWh basis. However, the spread between the New York City natural gas price and the price of Central Appalachian coal narrowed significantly due to the increase in the New York City natural gas price.

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 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

In November, wholesale electricity and natural gas prices were generally on the lower end of each hubs’ 12-month range and set new 12-month lows in a couple instances. A main driver for these lower prices, and energy demand, was warm weather across the West and the South. Wholesale electricity prices in New England (ISONE) set a new 12-month low of $15.54/MWh on November 3. In the Mid-Atlantic (PJM), a new 12-month low of $23.08/MWh was set on November 24. In the Midwest (MISO), a new 12-month low of $20.75/MWh was set on November 24. In California, prices moderated considerably compared to the last three months, when scorching temperatures drove peak prices above $125/MWh in both Northern and Southern California from August through October. Prices peaked at $60/MWh in Southern California (CAISO) and $59/MWh in Northern California (CAISO).

Wholesale natural gas at the Henry Hub in Louisiana, historically the proxy price point for the United States, ranged between $2.68-$3.18/MMBtu during the month. The largest deviation from the Henry Hub occurred in the Northeast, as is typical most months. This region deals with both abundant production and lack of takeaway pipeline capacity in the Marcellus region in Pennsylvania, which depresses prices, as well as a lack of adequate pipeline capacity into New York City and New England, which causes price spikes. During November, the lowest priced natural gas in the country was found in the Mid-Atlantic at Tetco M-3, a price point in eastern Pennsylvania close to the heart of Marcellus production. Prices there hit $0.82/MMBtu on November 6, though that was still well higher than the $0.52/MMBtu 12-month low at this location. The highest priced natural gas in the country was found just 300 miles or so northeast of Tetco M-3 at Algonquin Citygates near Boston. Prices at Algonquin hit $8.75/MMBtu on November 10, though this is just a fraction of what prices can hit in this region during peak winter days, just four days after setting a new 12-month low there at $1.04/MMBtu. The reason for this abrupt change in New England? The arrival of a cold front that caused temperatures in Boston to plummet from a high of 64 degrees Fahrenheit on November 6 to a low of 24 degrees on November 10.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand levels were lower across most regions in November compared to one month prior due to much warmer than normal temperatures across most of the country that kept temperatures mild and energy demand towards the lower end of the 12-month range. Though no new 12-month low daily peak days were set, every region except Progress Florida (which would have been close, absent the arrival of Hurricane Irma in early September) had daily peak demand days near 12-month lows. These periods of low demand in October and November are the main reason that transmission and generator maintenance outages jump this time of year, as equipment is made ready for the higher demand winter months ahead.

 

Electric Power Sector Coal Stocks: November 2017

 



In November 2017, U.S. coal stockpiles increased to 143 million tons, up 1.4% from the previous month. This increase in total coal stockpiles is a normal occurence as coal power plants start building their stockpiles during the fall months in order to meet greater demand for electricity during the winter.

Days of burn




The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn decreased from 90 days of burn in October 2017 to 87 days of forward-looking days of burn in November 2017. For subbituminous units largely located in the western United States, the average number of days of burn increased slightly compared to the previous month, going from 84 days of burn in October 2017 to 85 days of burn in November 2017.

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

  November 2017   November 2016   October 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 4,307 79   5,971 77 -27.9% 4,714 90 -8.6%
  Subbituminous 163 92   153 63 6.6% 146 99 11.3%
South Bituminous 28,233 91   30,712 82 -8.1% 27,570 92 2.4%
  Subbituminous 5,566 64   6,491 75 -14.2% 5,359 64 3.9%
Midwest Bituminous 13,635 81   17,151 90 -20.5% 13,270 83 2.8%
  Subbituminous 37,940 87   45,247 85 -16.1% 37,476 84 1.2%
West Bituminous 5,133 90   6,099 93 -15.8% 5,312 91 -3.4%
  Subbituminous 26,830 90   34,098 102 -21.3% 26,295 89 2.0%
U.S. Total Bituminous 51,308 87   59,933 85 -14.4% 50,867 90 0.9%
  Subbituminous 70,500 85   85,988 90 -18.0% 69,276 84 1.8%

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.