U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for July 2016 | Release Date: Sep. 27, 2016 | Next Release Date: Oct. 25, 2016
Highlights: July 2016
- Daily peak electricity demand in New York (NYISO) and PJM reached their highest levels since 2013.
- Most trading hubs were at or near 12-month high electricity prices due to very high demand levels and rising natural gas prices.
- For the second consecutive month, the price of natural gas at Henry Hub was above the price of Central Appalachian coal on a $/MWh basis.
|July 2016||% Change from July 2015|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Wind generation share exceeds 10% in 11 states
Of the 39 states with utility-scale wind farms, 11 states generated 10% of their total electricity from wind in 2015. Only 3 states had this share of wind generation in 2010.
In 2015, Iowa had the largest wind generation share (31.3%). South Dakota (25.5%) and Kansas (23.9%) had wind generation shares in excess of 20%. Two additional states, Texas and New Mexico, are on track to surpass the 10% wind generation share in 2016.
A utility-scale wind farm is one where the aggregate capacity of the wind turbines is equal to or greater than 1 megawatt (MW).Source: U.S. Energy Information Administration, Power Plant Operations Report (Form EIA-923) preliminary monthly 2015 data.
At the national level, wind's share of total U.S. electricity generation has risen every year since 2001. Wind facilities produced 190,927 gigawatt hours (GWh) of electricity in 2015, accounting for 4.7% of net U.S. electric power generation. This level represents a doubling of wind's generation share since 2010, when the share was 2.3%.
The increase of wind power in the U.S has been driven by a variety of factors including the presence of the Federal Production Tax Credit (PTC), Investment Tax Credit (ITC), state level renewable portfolio standards (RPS), improved wind technology, and increased access to transmission capacity. The PTC grants a federal tax credit on wind generation, while the ITC allows for federal tax credits on wind farm investments. State RPS, meanwhile, require that a minimum percentage of electricity generation come from renewable energy.Source: U.S. Energy Information Administration, Power Plant Operations Report (Form EIA-923) 2001-2014 final annual data, 2015 preliminary monthly data.
Another important factor to wind power's growth is the local wind resource base. The map below illustrates that states with high wind generation shares are located in the Central High Plains and the Rocky Mountains.Source: U.S. Energy Information Administration, Power Plant Operations Report (Form EIA-923) preliminary monthly 2015 data.
States with the highest shares of electricity generation from wind match up with high wind resource areas. The map below shows average wind speeds at 80 meters in meters per second (m/s) across the U.S. The three states (Iowa, South Dakota, and Kansas) whose wind's share were 20% or more in 2015 are located in the highest wind resource regions. Four other states (Oklahoma, North Dakota, Minnesota and Colorado) with wind generation shares between 10% and 20% also are located in high-wind areas.
State-level RPS that require a minimum percentage of electricity generation from renewable energy and other state-level programs have also resulted in rising wind generation. Twenty-nine states and the District of Columbia have RPS policies, and an additional eight states have renewable portfolio goals. Besides RPS, many states provided incentives, such as exemption from property tax, mandated purchases, and additional programs to encourage wind power in their state.
For example, Iowa passed one of the country's first renewable generation laws in 1983. The Alternative Energy Law requires Iowa investor-owned utilities (IOUs) to own or contract for at 105 MW of capacity from renewable energy.
South Dakota set a renewable energy target in 2008 that 10% of all retail electricity sales would be generated from renewable sources by 2015.
Kansas passed an RPS in 2009 requiring certain utilities to generate or purchase 15% of their electricity from renewable resources between 2015 and 2019. In 2015, the Kansas legislature, changed the required standard to a goal of 20% by 2020.
In 2010, Oklahoma enacted a renewable energy goal that 15% of total installed generation capacity would be from operating electric utilities to be renewable sources by 2015.
North Dakota, in 2007, set a voluntary target that by 2015, 10% of all electricity sold in the state would come from renewable sources.
Minnesota passed a renewable energy standard in 2007 that places a 26.5% renewable requirement on IOUs and a 25% requirement on other utilities. Xcel energy has a separate renewable requirement of 31.5% by 2020.
Vermont initially passed a voluntary renewable goal in 2005 that was subsequently changed to a mandatory renewable standard in 2015. The standard requires that 75% of retail sales, by 2032, come from renewable resources. The standard also sets an interim goal of 55% in 2017.
Idaho does not have a RPS, but in 2007, Idaho enacted a bill that restructured the method of taxation for producers of wind energy from a property tax to a tax on production. This restructuring aimed to ease the burden on commercial wind farms in the early years of operation.
Oregon first enacted a RPS in 2007. In 2016, the state legislature increased the state's RPS percentage requirements. The current RPS calls for utilities to meet their sales requirements using 25% renewable sources by 2025, with the percentage requirement increasing to 50% by 2040.
Maine enacted a RPS in 1999 that calls for 40% of electricity generation to come from renewables by 2017. The state also has three wind energy development goals: 2,000 MW of installed capacity by 2015; at least 3,000 MW of installed capacity by 2020, and at least 8,000 MW of installed capacity by 2030.
End Use: July 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 29 states in July compared to last year. The largest declines were found in Nevada (down 10.9%), Mississippi (down nearly 10%), and Georgia (down 9.4%). Twenty states increased compared to last year, led by West Virginia (up 7.2%), Maine (up nearly 5.2%) and South Dakota (up 4.7%).
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector July 2016 Change from July 2015 July 2016 Change from July 2015 Year to Date Residential 12.68 -2.4% 153,952 5.9% 807,172 Commercial 10.62 -3.6% 129,233 0.6% 778,266 Industrial 7.23 -2.8% 83,301 -2.5% 544,312 Transportation 9.69 -7.4% 651 0.1% 4,388 Total 10.71 -2.3% 367,137 2.0% 2,134,139
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour were down 2.3% to 10.71 cents in July compared to last year. All sectors were down on the month, from a 7.4% drop in the Transportation sector to a 2.4% drop in the Residential sector. Retail sales were up slightly overall (2.0%) to 367,137 gigawatthours (GWh). The Residential, Commercial, and Transportation sectors showed slight gains of 5.9%, 0.6%, and 0.1%, respectively, while the Industrial sector showed a decline of 2.5%..
State retail sales volumes were down in 12 states in July compared to last year. Maine recorded the largest year-over-year decline, down 9.3%. Oregon, Washington, and California had the next largest declines, all down 6.9 - 5.2%. Thirty-eight states and the District of Columbia had retail sales volume increases in July, led by Colorado (up 7.8%), Arizona, and Michigan (both up 6.9%).
Cooling Degree Days (CDD) were higher across most of the country, up in 43 states and the District of Columbia compared to last July. The largest year-over-year increase was found in Michigan, followed by Alaska, New Mexico, Utah, and Wyoming in the Mountain West, and Maine in the Northeast. Eight states had less CDDs than last July, with these states largely found in the Pacific Northwest and upper Mountain West. Oregon had the largest CDD decrease of any state, followed by Washington, Hawaii, Idaho, North Dakota, and Montana.
Resource Use: July 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
In July 2016, net generation in the United States increased 2.9% from the previous year. This occurred because the country, as a whole, experienced above average temperatures in July 2016 compared to last July when temperatures were average. This led to an increased need for residential cooling this year and thus, an increase in electricity generation. At the regional-level, all regions of the country saw an increase in electricity generation compared to July 2015.
The change in electricity generation from coal compared to the previous July was mixed throughout the country. The Northeast, MidAtlantic, Florida, and Texas all saw increases in coal generation from the previous year, while the Southeast, Central, and Western regions all saw a decrease in coal generation. Natural gas generation increased from the previous year in all parts of the country except for in Texas and the West. This decrease in both coal and natural gas generation in the West occurred because the region, and more specifically the Northwest part of the country, saw a large increase in hydroelectric generation in July 2016. Electricity generation from other renewables increased in all regions of the country except for Florida. Texas had the largest percentage increase in other renewables generation, up 36.3% from the previous July, mainly due to many new wind farms coming online since last year and also the addition of the OCI Alamo 5 LLC solar plant.
Fossil fuel consumption by region
The chart above compares coal consumption in July 2015 and July 2016 by region and shows that the change in coal consumption mostly mirrored the change in electricity generation from coal. The largest percentage increase in coal consumption occurred in the Northeast (9.6%), where the consumption of coal for electricity generation is almost negligible. The largest decrease in coal consumption compared to the previous July occurred in the Central region (-7.8%).
The second tab compares natural gas consumption by region and shows that changes in natural gas consumption from the previous July were similar to the changes in electricity generation from natural gas over the same period. The largest percentage increase in natural gas consumption occurred in the MidAtlantic (25.6%) and the Central (25.1%) regions, while the West (-3.5%) had the largest percentage decrease compared to July 2015.
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 2016, the share of natural gas consumption increased in almost all regions of the country at the expense of coal consumption compared to the previous year. The only outliers were in Texas and the Northeast, where coal consumption increased slightly at the expense of natural gas compared to the previous July.
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 $2.64/MMBtu in June 2016 to $2.89/MMBtu in July 2016. The natural gas price for New York City (Transco Zone 6 NY) also increased, going from $1.89/MMBtu in June 2016 to $2.23/MMBtu in July 2016.
For the first time since January 2016, the New York Harbor residual oil price decreased from the previous month, going from $7.67/MMBtu in June 2016 to $7.59/MMBtu in July 2016. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.
A fuel price comparison based on equivalent energy content ($/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. For the second consecutive month, the price of natural gas at Henry Hub was above the price of Central Appalachian coal on a $/MWh basis. This was mainly due to the increase in the price of natural gas at Henry Hub. The price of natural gas at New York City on a $/MWh basis was still below the price of Central Appalachian coal for a fifth consecutive month, however, the spread between the two prices decreased significantly 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: July 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 electricity prices were at or near yearly highs in July at all hubs except Texas (ERCOT). This was the product of high electricity system demand and rising natural gas prices, both of which were also at or near yearly highs in most regions. Yearly high electricity prices were set in the Midwest (MISO) at $55/MWh, Louisiana (into Entergy) at $42/MWh, the Southwest (Palo Verde) at $72/MWh, Southern California (CAISO) at $61/MWh, Northern California (CAISO) at $58/MWh, and in the Northwest (Mid-C) at $75/MWh. Wholesale electricity prices in New York City (NYISO) and the Mid-Atlantic were within $1/MWh of yearly highs.
Wholesale natural gas prices have trended steadily upwards since March as very high natural gas demand from power generators and falling natural gas production have chipped away at the large natural gas storage overhang. A yearly high was set in Southern California (SoCal Border) at $3.42/MMBtu and was within pennies of yearly highs in Louisiana (Henry Hub), Texas (Houston Ship Channel), and Northern California (PG&E Citygate). The Northeast and Mid-Atlantic were the only regions where natural gas prices were not at or near record highs, as pipeline constraints in the winter cause much higher prices during the December-February time frame.
Electricity system daily peak demand
Electricity system daily peak demand was very high across all regions except the Northwest (Bonneville Power Administration) in July. 12-month high daily peaks were set in New England (ISONE), New York State (NYISO), the Mid-Atlantic (PJM), and the Midwest (MISO). NYISO's daily peak of 31,187 MW on July 22 was its highest daily peak load since September 11, 2013. PJM's daily peak of 151,882 MW on July 25 was its highest daily peak load since July 19, 2013.
Electric Power Sector Coal Stocks: July 2016
In July, U.S. coal stockpiles decreased to 172 million tons, down 7.4% from the previous month. As a whole, U.S. coal stockpiles have decreased 22.6 million tons from this year's high of 194 million tons in March. However, U.S. coal stockpiles are still at relatively high levels becaue coal continues to lose market share to natural gas in most 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 86 days of burn in June to 87 days of forward-looking days of burn in July. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 79 days in June to 80 days in July.
Coal stocks and average number of days of burn for non-lignite coal by region (electric power sector)
|July 2016||July 2015||June 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|
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.
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.
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 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.