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Electricity Monthly Update

With Data for August 2017  |  Release Date: October 24, 2017  |  Next Release Date: November 27, 2017
Re-release date: October 25, 2017   |   Revision

Previous Issues

Highlights: August 2017

  • Record heat led to new 12-month high wholesale electricity prices in California, the Northwest, and Southwest in August 2017.
  • Hurricane Harvey caused a significant drop in electricity demand in Texas (ERCOT) in the days after making landfall on August 25.
  • Net generation in the U.S. decreased by 7.2% compared to the previous August, mainly due to the cooler temperatures experienced in August 2017 compared to the previous year.

Key indicators




Aging wind turbines and advances in wind turbine technology create a potential for wind repowering in the United States

The wind repowering market in the United States has the potential for significant growth, primarily because of an aging fleet of turbines and advances in wind turbine technology. Although only about 3,226 Megawatts (4%) of the total wind capacity at the end of 2016 was older than 15 years, almost 15% of the individual wind turbines predated 2001.

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report, early release 2016 data.

In December 2015, the Production Tax Credit (PTC) was extended until the end of 2019. Although the PTC traditionally applied to new installations, the four-year extension and phase-out of the PTC is expected to encourage many asset owners to repower existing wind facilities to re-qualify them to receive another 10 years of tax credits. Under IRS rules, retrofitted facilities that retain portions of the existing assets may also qualify for PTCs under the 5% Safe Harbor, where the fair market value of those portions is not more than 20% of the wind power facility’s total value (the new investment plus the value of the existing asset, called the 80/20 Rule).

Repowering projects at wind facilities can be full or partial. Full repowering refers to complete decommissioning and removal of existing turbines and replacement with modern units at the same project site. Full repowering (also called traditional repowering) mostly has occurred in California, where many turbines were installed in high-wind sites before 1990. Partial repowering, on the other hand, involves leaving some portion of the existing wind asset and replacing select components. By partially repowering, owners can take increase hub heights and rotor diameters to produce more energy output.

Although wind turbines are designed with lifespans of between 20 and 25 years, according to The U.S. Department of Energy’s Wind Technologies Market Report, wind capacity factors decline with age. The UK’s Engineering and Physical Sciences Research Council in 2014 indicated that, on average, the output of the wind turbines decline by 1.6% each year. Repowering can be an affordable way to increase the output of a wind facility, improve reliability, and extend the life of a facility by taking advantage of advanced turbine technology.

Replacing old turbines with new ones can raise output by a factor of two or more. Modern turbines tend to run much more slowly and quietly than older, smaller turbines, turning at 10–20 revolutions per minute (rpm) instead of 40–60 rpm. Lower rotational speeds also reduce bird mortality. Repowering generally requires significantly less capital than investing in a new project.

According to GE, repowering wind turbines can increase the fleet output by 25% and can add 20 years to turbine life from the time of the repower. GE is the largest wind turbine installer in the United States, accounting for more than 41% of the total U.S. utility-scale operating turbines. GE recently repowered 300 wind turbines, which is equivalent of adding 75 new wind turbines, and the company expects this market to grow.

The National Renewable Energy Laboratory (NREL) has indicated that U.S. wind repowering investment has the potential to grow to $25 billion by 2030. Currently, U.S. Energy Information Administration Form EIA-860 data indicate that three projects are currently planned for repowering. Mendota Hills, LLC in Illinois and Sweetwater Wind 2 LLC in Texas are scheduled for repowering in 2018, and Windpark Unlimited 1 located in California is scheduled for repowering in 2022.

Although the potential benefits from repowering can be significant, challenges remain. For example, increased risk of failure exists when reusing components such as towers and foundations. Other challenges included the renegotiation of power purchase agreements, interconnection agreements, and leases. Despite these challenges, the aging fleet of wind turbines and the advances in wind turbine technology create opportunities for growth in wind facility capacity.


Principal Contributor:

Suparna Ray
(Suparna.Ray@eia.gov)

 

End Use: August 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 and the District of Columbia in August compared to last year. The largest declines were found in the District of Columbia (down 3.7%), Michigan (down almost 2.8%), and New Jersey (down almost 2.7%). Thirty seven states increased revenue per kilowatthour compared to last year, led by Massachusetts (up 6.2%), Mississippi (up 6.15%), and Connecticut (up just over 6%).


Total average revenues per kilowatthour were up 1.4% to 10.98 cents in August compared to last year. All sectors were up on the month, with the Commercial sector leading at 3.1%. The Residential and Transportation sectors followed with 2.2% and 1.8% increases, respectively. Retail sales were down 5.3% for the month. The Residential sector showed the greatest decline, down 9.1%. The Commercial sector followed with a 4.8% drop. The Transportation and Industrial sectors rose slightly, up 1.5% and 0.9%, respectively.

Retail sales



State retail sales volumes were down in 41 states and the District of Columbia in August compared to last year. Maryland showed the largest year-over-year decline, down 14.4%. New Jersey and Illinois had the next largest declines, down 14% and 13.5%, respectively. Nine states had retail sales volume increases in August, led by Montana (up 4.3%), Oregon (up 2.8%), and Utah (up 2.6%).


Cooling Degree Days (CDD) were down in 43 states and the District of Columbia compared to last August. The largest year-over-year decrease was found in Wisconsin. It had a decrease of 127 CDDs, just over 65%. Also in the region, second-place Michigan had a 151 CDD-decrease (over 59%) from August 2016. Eight other states had a decrease of over 50% in CDDs: Massachusetts, New Hampshire, Pennsylvania, Indiana, Illinois, Ohio, Rhode Island, and Maine. This was due to milder weather in those regions compared with last August. Seven states had an increase in CDDs from the prior year, led by Alaska (up 100%), Montana (up 19%), Oregon (up 17.7%), and Idaho (up 15%).

 

Resource Use: August 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 by 7.2% compared to August 2016. This year-over-year decrease in electricity generation occurred primarily because the country experienced a much cooler August in 2017 than it did the previous year. This led to a decreased need for residential and commercial customer cooling compared to August 2016 and thus, a decreased need for electricity generation. At the regional-level, all regions of the country, except for Florida, saw a decrease in electricity generation from the previous August.

All regions of the country, except for the West region, saw a decrease in electricity generation from coal compared to the previous year. Except for Florida, all regions of the country saw a decrease in natural gas generation compared to August 2016. The MidAtlantic saw both the largest drop in coal generation (-6,543 gigawatthours) and the largest drop in natural gas generation (-6,938 gigawatthours).

Net generation from nuclear was up 1.2% compared to the previous year. Hydroelectric generation was up in all regions of the country except for Texas and the Central region. The Western region still continued the trend of experiencing an increase in hydroelectric generation (7.2%) compared to the previous year.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in August 2016 and August 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 August 2017, the MidAtlantic, Central, West, and Texas all saw an increase in the share of coal consumption at the expense of natural gas. The Northeast, Southeast, and Florida all saw an increase in the share of natural gas consumption 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 decreased slightly from the previous month, going from $3.04/MMBtu in July 2017 to $2.97/MMBtu in August 2017. The natural gas price for New York City (Transco Zone 6 NY) also decreased from the previous month, going from $2.53/MMBtu in July 2017 to $2.21/MMBtu in August 2017. The average price of Central Appalachian coal remained relatively flat for a third month in a row, only decreasing from $2.27/MMBtu in July 2017 to $2.26/MMBtu in August 2017.

For the second consecutive month, the New York Harbor residual oil price increased from $8.32/MMBtu in July 2017 to $8.54/MMBtu in August 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 ($23.78/MWh) was below the price of Central Appalachian coal ($24.44/MWh) on a $/MWh basis. The price of natural gas at New York City ($17.71/MWh) on a $/MWh basis was below the price of Central Appalachian coal ($24.44/MWh), and the spread between the two widened considerably mainly 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: August 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 electricity prices in August directly reflected the temperatures experienced in each region. Much of the West spent the month stuck under a high pressure ridge that brought extreme heat to the region and broke numerous high temperature records. California, Oregon, and Washington recorded their hottest Augusts’ (by average temperature) on record. Wholesale electricity prices in Northern and Southern California (CAISO), the Northwest (Mid-C), and the Southwest (Palo Verde) reflected this heat, with high prices for the month more than twice as expensive as any other selected trading hub and setting new 12-month high for each of the four hubs. In the Southwest (Palo Verde), prices reached $139/MWh on August 28, 2017 and topped out at $147/MWh on August 29, 2017. In California, prices exceeded $100/MWh in Southern California (CAISO, SP15) and Northern California (CAISO, NP15) on August 1, 2, 28 and 29, peaking on August 28, 2017 at $144/MWh in Southern California and $145/MWh in Northern California. Electricity prices in the rest of the country were much lower, between $17-$55/MWh during the month, as many states east of the Rockies recorded below- to much-below normal temperatures.

Wholesale natural gas prices at the Henry Hub in Louisiana, traditionally the main natural gas pricing point in the U.S. traded in a tight band between $2.75-$3.02/MMBtu during the month. Natural gas prices in the Northeast traded lower than the Henry Hub for all but two days during the month, down to $1.37/MMBtu in the Mid-Atlantic (Tetco M-3), $1.45/MMBtu in New York City (Transco Z6 NY) and $1.75/MMBtu in New England (Algonquin). Prices in the Northeast/Mid-Atlantic displayed an exaggerated seasonality, with prices lower from the spring to fall non-peak season as excess production has difficulty getting out of the region while spiking high in the winter during peak heating demand season as temperatures plunge and pipeline constraints into the region come into play. The highest wholesale natural gas prices during the month (of the selected trading hubs) occurred in Southern California (SoCal Border), reaching a new 12-month high of $4.10/MMBtu on August 30, 2017.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand levels, though high and reflective of August summer conditions, were lower than peak demand levels reached in July in all regions except California (CAISO). This was due to below-normal temperatures in most states east of the Rockies and Hurricane Harvey’s landfall in Texas. In California, record heat in both the beginning and the end of the month lead to very high electricity demand, topping out at over 47.3 gigawatts (GW) on August 28, 2017, a new 12-month high in CAISO. In Texas, Hurricane Harvey made landfall on August 25, 2017, causing daily peak electricity demand in ERCOT to fall from 60-67 GW daily peak range in the week prior to landfall to only 41.7 GW on August 27, 2017 before rebounding steadily through the end of the month. Demand reached 43.46 GW on August 16, 2017 in Southern Company, just 0.1 GW short of its annual max set last month.

 

Electric Power Sector Coal Stocks: August 2017

 



In August 2017, U.S. coal stockpiles decreased to 144 million tons, down 2.7% from the previous month. This decrease in total coal stockpiles is a normal occurence during the summer months when demand for electricity is greater.

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 76 days of burn in July 2017 to 89 days of forward-looking days of burn in August 2017. For subbituminous units largely located in the western United States, the average number of days of burn increased from 72 days in July 2017 to 79 days in August 2017.

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

  August 2017   August 2016   July 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 4,143 88   5,312 98 -22.0% 3,915 72 5.8%
  Subbituminous 129 139   153 131 -15.6% 129 166 0.0%
South Bituminous 27,973 91   27,906 84 0.2% 28,498 75 -1.8%
  Subbituminous 5,362 59   5,899 67 -9.1% 5,709 55 -6.1%
Midwest Bituminous 13,187 83   16,830 99 -21.6% 13,750 76 -4.1%
  Subbituminous 36,407 80   40,679 82 -10.5% 38,044 73 -4.3%
West Bituminous 5,457 90   5,715 79 -4.5% 5,576 82 -2.1%
  Subbituminous 26,995 83   31,529 92 -14.4% 28,432 74 -5.1%
U.S. Total Bituminous 50,760 89   55,763 89 -9.0% 51,738 76 -1.9%
  Subbituminous 68,894 79   78,259 84 -12.0% 72,313 72 -4.7%

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.