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Electricity Monthly Update

With Data for July 2015  |  Release Date: Sep. 28, 2015  |  Next Release Date: Oct. 26, 2015

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Highlights: July 2015

  • Electricity demand rose steadily throughout the month, setting new 12-month system daily peak demand highs in five regions.
  • Electricity generation from coal decreased in all regions of the country, while electricity generation from natural gas increased in all regions of the country compared to the previous July.
  • Hawaii's average revenue per kilowatthour was down 22%, the seventh month in a row Hawaii has had the largest decline of any state.

Key Indicators

  July 2015 % Change from July 2014
Total Net Generation
(Thousand MWh)
399,620 3.7%
Residential Retail Price
12.98 -0.5%
Retail Sales
(Thousand MWh)
359,562 3.5%
Cooling Degree-Days 342 11.0%
Natural Gas Price, Henry Hub
2.91 -29.7%
Natural Gas Consumption
1,078,451 23.2%
Coal Consumption
(Thousand Tons)
76,401 -6.3%
Coal Stocks
(Thousand Tons)
160,206 27.9%
Nuclear Generation
(Thousand MWh)
71,412 -0.7%

Coal stockpiles in 2015 return to historical levels after early 2014 drawdown

Source: U.S. Energy Information Administration, Form EIA-923 "Power Plant Operations Report"

Since falling to 118 million tons in March 2014, the lowest level since March 2006, coal stockpiles at electric power plants have returned to quantities that are more in line with same-month totals from previous years. December 2014 marked the first time since December 2012 that stockpiles were higher than they had been in the same month of the previous calendar year. Additionally, since December 2014, coal stocks have been higher than the same month of the previous year every month through July 2015.

The winter of 2013-14 was extremely cold relative to both the previous winter and normal winters, and more fuel, including coal, was burned to generate electricity to meet higher heating loads across the northern United States. This increased fuel use, coupled with limited coal deliveries in the Midwest from the Burlington Northern Santa Fe (BNSF) system, contributed to the significant drawdown in coal stockpiles. Total U.S. net electricity generation was 5.3% higher from November 2013 through February 2014 than it had been in the November 2012 through February 2013 period, and 59% of that increase in electricity was supplied by coal generation, which was up 8% from levels a year earlier.

Conversely, temperatures in the winter of 2014-15 were higher than normal, and a lot less fuel was needed to generate electricity for heating purposes. Subbituminous coal stocks at electric power plants actually increased - highly atypical in winter months - because February 2015 in the western states, where most but not all subbituminous coal is burned, was one of the warmest on record. The BNSF delivery problems that contributed to shrinking piles the year before were mitigated as well, leading to larger stockpiles.

Another aspect contributing to the increase in coal stocks this year is the fall in natural gas prices. Prices of natural gas used to generate electric power in June 2015 were less than half the level in January 2014 when coal stockpiles began to shrink so rapidly. In fact, in April 2015, for the first time since EIA began collecting monthly generation data in 1973, generation of electricity fueled by natural gas exceeded coal-fired generation. As natural gas has become a more economical fuel option, coal consumption has fallen and resulted in higher coal stockpiles than would have been expected in the absence of the natural gas price decline.

Principal Contributors:

Ronald Hankey

April Lee


End Use: July 2015

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 were higher in 30 states and the District of Columbia and lower in 20 states during the month of July. Iowa had the largest increase for the second month in a row, up nearly 12% compared to last year. Five states geographically scattered across the country were up between 5-10% from last year: West Virginia (up nearly 10%), Georgia (up 8%), Rhode Island (up 7%), Washington (up 6%) and Illinois (up nearly 6%). Fourteen states increased between 2-5% and 11 states were up slightly, between 0-2% compared to last July. Hawaii had the largest decline of any state for the seventh month in a row and has had year-over-year declines of greater than 20% for five months running. Hawaii's bulk power system is largely petroleum-fueled and has benefitted greatly from the large fall in world oil prices that began in the latter half of 2014. Louisiana had the next greatest drop, down over 12%, with Nevada (down nearly 8%), Oklahoma (down nearly 6%) and Texas (down over 5%) experiencing the next largest year-over-year declines.

Total average revenues per kilowatthour were 10.95 cents in July, down 0.6% from last year. For the second month in a row, every sector saw declines, with the Industrial sector down 2.7%, the Commercial sector down 1.0%, the Residential sector down 0.5%, and the Transportation sector down 0.4%.

Total retail sales volumes were up 3.5% to 359,549 GWh in July compared to last year. The largest increase occurred in the largest sector by volume, with the Residential sector up 6.7% to 145,414 GWh. The Industrial sector was the only sector declining in volume from last year, down 0.2% to 84,075 GWh.

Retail sales

Electric industry retail sales volume trends in July matched weather patterns nearly identically by state, with those states hotter than last year having increased retail sales volumes and vice versa. Nearly every state outside of New England, the Southwest, and the Rocky Mountain states had increased retail sales volumes from last year; 37 states and the District of Columbia in total. Every one of those states except for Montana also had higher cooling degree day totals, indicating hotter weather and increased climate control demand contributing to higher retail sales volumes. North Dakota and Oklahoma had the largest year-over-year increases, up over 9%, with a handful of states (Montana, North Carolina, Georgia, Arkansas, and Missouri) up over 7%.

Thirteen states had lower retail sales volumes compared to last year and of these states, only Massachusetts and Rhode Island had lower volumes despite higher levels of cooling degree days. Wyoming had by far the largest decline in volumes, down over 11%, followed by Utah, down nearly 6%, and Idaho, down over 5%.

Cooling Degree Day (CDD) trends were fairly clear and consistent in July. Most states in the Rocky Mountain/Southwest region and New England had lower levels of CDDs than last year, and everywhere else in the country had higher levels of CDDs compared to last year. The largest increases were found in Wisconsin and Michigan, up 88% and 70% respectively, with Arkansas and Alaska up over 57%. The three largest year-over-year declines were found in Rocky Mountain states, with Utah down 42%, Idaho down 29%, and Wyoming down 27%.


Resource Use: July 2015

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 3.7% compared to July 2014. At the regional level, all regions except for the West saw an increase in electricity generation compared to the previous year. The Southeast and Central regions saw the largest percent change in electricity generation, as both experienced significantly warmer temperatures in July 2015 compared to July 2014. The West saw a decrease in electricity generation because last July the region experienced significantly higher temperatures, whereas this July, temperatures were more moderate.

Electricity generation from coal decreased in all regions of the country, while electricity generation from natural gas increased in all regions of the country compared to the previous July. Total electricity generation from nuclear was down slightly, decreasing 0.7% compared to the previous July. The Northeast saw the largest percent decrease in nuclear generation compared to last year, as the Vermont Yankee nuclear plant retired at the end of 2014. Electricity generation from conventional hydroelectric generators was down significantly in the West compared to last July, as the region continues to suffer from severe drought conditions.

Fossil fuel consumption by region

map showing electricity regions

The chart above compares coal consumption in July 2014 and July 2015 by region and shows that, like electricity generation from coal, coal consumption decreased in all regions of the country.

The second tab compares natural gas consumption by region and shows that all regions of the country saw an increase in natural gas consumption.

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 July 2015, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption 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 very 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 slightly from the previous month, going from $2.85/MMBtu in June 2015 to $2.91/MMBtu in July 2015. However, the natural gas price for New York City (Transco Zone 6 NY) saw a decrease from the previous month, going from $2.38/MMBtu in June 2015 to $2.06/MMBtu in July 2015.

The New York Harbor residual oil price saw a significant decrease from the previous month, going from $9.81/MMBtu in June 2015 to $8.69/MMBtu in July 2015. 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 seventh consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. However, the spread between the two prices narrowed slightly due to the month-to-month increase in the price of natural gas at Henry Hub. The spread between the New York City gas price and the price of Central Appalachian coal also increased compared to the previous month, a result of the increase in the natural gas price of 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: July 2015

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 reflected high electricity demand during the month of July, setting or approaching 12-month highs in many regions. The Northwest (Mid-C) set an annual high of $99/MWh, Northern CA (CAISO) set an annual high of $75/MWh, and Southwest (Palo Verde) set an annual high of $65/MWh. These high prices were set on July 1 when electricity demand throughout the Northwest and California was high, wind generation was low (particularly in the Northwest), and hydroelectric generation remained depressed, as it has been all summer. Outflows measured at the Dalles, a key run-of-river dam on the Columbia River east of Portland and proxy for hydroelectric generation, totaled only 128,000 cubic feet per second on July 1, less than 40% of the five-year average for this date. The Dalles outflows have remained below the previous five-year range, considerably so at times, virtually every day from late-April through the end of July. Wholesale electricity prices were also high in the Northeast, $103/MWh at Mid-Atlantic (PJM), $72/MWh in New York City (NYISO), and $62/MWh in New England (ISONE), though these prices did not approach highs set last winter when natural gas prices were considerably higher.

Wholesale natural gas prices remained very low in July, dropping all the way to $0.77/MMBtu in the Mid-Atlantic (Tetco M-3), $0.87/MMBtu in New York City (Transco Z6 NY), and $1.02/MMBtu in New England (Algonquin), all new lows for the previous 12-month period. Prices stayed below $3/MMBtu across most the country for most of the month.

Electricity system daily peak demand

Electric systems selected for daily peak demand

Electricity system daily peak demand was high in July, setting new 12-month highs in several regions. New 12-month highs were set in New England (ISONE) at 24.3 GW, New York State (NYISO) at 31.1 GW, the Mid-Atlantic (PJM) at 143.7 GW, the Midwest (MISO) at 120 GW, and in Texas (ERCOT) at 67.6 GW (ERCOT was very close to setting a new all-time peak demand record as well). Daily peak demand generally rose throughout the month and monthly peaks were reached between July 28-30 in all regions except Progress Florida, which reached its daily peak for the month on July 10.


Electric Power Sector Coal Stocks: July 2015


In July, U.S. coal stockpiles decreased to 160 million tons, down 5% from the previous month. This decrease in June-to-July coal stockpiles follows the normal seasonal pattern whereby coal stockpiles decrease during the summer months. Despite this decrease, coal stockpiles are still at relatively high levels due to a loss in market share to natural gas in all regions of the country.

Days of burn

The average number of days of burn held at electric power plants is a forward-looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. For bituminous units largely located in the eastern United States, the average number of days of burn increased from 73 days to 77 days of forward-looking days of burn estimates. For subbituminous units largely located in the western United States, the average number of days of burn increased slightly, going from 65 days in June to 66 days in July. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn decreased slightly from the previous month, going from 9.2% in June to 8.8% in July. This is a much lower percentage than last July, when over 24% of units had less than 30 days of burn.

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

  July 2015   July 2014   June 2015  
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 6,735 112   5,342 71 26.1% 6,937 99 -2.9%
  Subbituminous 762 217   308 90 147.4% 806 229 -5.5%
South Bituminous 30,694 73   27,898 60 10.0% 33,584 71 -8.6%
  Subbituminous 5,865 63   5,541 54 5.9% 6,457 68 -9.2%
Midwest Bituminous 14,762 75   11,488 53 28.5% 15,836 73 -6.8%
  Subbituminous 36,809 59   27,133 41 35.7% 38,557 58 -4.5%
West Bituminous 5,364 68   4,564 54 17.5% 5,594 69 -4.1%
  Subbituminous 31,668 76   18,992 42 66.7% 32,852 74 -3.6%
U.S. Total Bituminous 57,555 77   49,292 59 16.8% 61,951 73 -7.1%
  Subbituminous 75,105 66   51,974 43 44.5% 78,673 65 -4.5%

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


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.