U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for June 2015 | Release Date: Aug. 26, 2015 | Next Release Date: Sep. 24, 2015
Highlights: June 2015
- Daily peak electricity demand was high in many parts of the country during one of the warmest June's on record for many states.
- Wholesale electricity prices remained moderate despite higher demand levels because of low natural gas prices, which approached $1/MMBtu at many locations during the month.
- Hawaii's average revenue per kilowatthour was down 23%, the sixth month in a row Hawaii has had the largest decline of any state.
|June 2015||% Change from June 2014|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Record utility-scale solar generation driven by photovoltaics in June 2015Source: U.S. Energy Information Administration, Form EIA-923 Power Plant Operations Report.
Solar generation from utility-scale facilities (capacity of 1 megawatt [MW] or greater) hit a monthly record high of 2,765 gigawatthours (GWh) in June 2015. The June 2015 solar generation level represents a year-over-year increase of 35.8% relative to June 2014.
The main driver to this growth was the continued expansion of solar photovoltaic capacity, which increased by 47.5% from June 2014 to June 2015. Over that same period, solar thermal capacity increased by 18.1%. Solar electricity output in June is a good indicator of the recent growth of the solar industry because June has the highest monthly average of sunlight per day.
Electricity output of U.S. utility-scale solar generators in June 2015 was 31 times the level in June 2005. Between 2005 and 2010, the vast majority of utility-scale solar generation came from large solar thermal facilities. Solar thermal facilities accounted for about 85% of total annual utility-scale solar generation from 2005 to 2010.
Beginning in 2011, photovoltaic generation began to grow at a higher rate than thermal generation, even though solar thermal generation has continued to expand as well. In 2014, the photovoltaic share was 86.6% of the total solar generation supplied to the electricity grid, with the 2015 year-to-date share through June being 87.6%.
Most of the growth in U.S. utility scale solar generation is in California. In June 2015, well over half (56.5%) of total solar generation came from plants in California. Arizona (13.4%), North Carolina (6.7%), Nevada (6.4%), and New Jersey (3.3%), respectively, followed California as the largest solar contributors to the grid.Source: U.S. Energy Information Administration, Form EIA-923 Power Plant Operations Report.
Solar capacity in the United States has grown at smaller units on residential and commercial rooftops and at other smaller facilities as reported by distribution utilities, which are typically net-metered (see April 2014 Electric Monthly Update).
Generators, including utility-scale solar units that are expected to come online soon, are shown on this map.
End Use: June 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 31 states and the District of Columbia, flat in two states and down in 17 states in June. Iowa had the largest increase, up over 12%, followed by Massachusetts and Washington, both up just over 9% compared to last year. Hawaii had the largest decline by a wide margin, down 23% from last year and the sixth month in row the state had the largest year-over-year drop. Hawaii's petroleum-heavy bulk power system has benefitted greatly from the large fall in world oil prices that began in the latter half of 2014. Louisiana had the next greatest year-over-year drop, down nearly 12%. Colorado, Georgia, New York, and Kentucky were next with declines between 5-10%.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector June 2015 Change from June 2014 June 2015 Change from June 2014 Year to Date Residential 12.93 -0.4% 119,949 2.0% 682,132 Commercial 10.87 -1.0% 119,898 0.6% 658,889 Industrial 6.98 -4.0% 82,641 1.0% 468,112 Transportation 10.20 -2.4% 606 -0.3% 3,844 Total 10.64 -1.1% 323,094 1.2% 1,812,978
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour were 10.64 cents in June, down 1.1% from last year. Every sector saw declines, from -4% in the Industrial sector to -0.4% in the Residential sector.
Total retail sales volumes were up 1.2% to 323,094 GWh in June compared to last year. The largest increase was found in the Residential sector (up 2%) and just edged out the Commercial sector (up 0.6%) as the sector with the largest retail sales volumes during the month. The Transportation sector, by far the smallest of the four, was the only sector declining from last year, down 0.3%. Retail sales volumes are up considerably from last month's total of 285,707 GWh as summer weather set in across much of the country.
Electric industry retail sales volume trends this June were notable for their lack of geographic consistency. Year-over-year retail sales volume changes varied a lot between neighboring states. Also, many states with lower retail sales levels were scattered throughout the country, with one or two in seemingly every region amongst a sea of states with higher year-over-year retail sales volumes.
For example, the largest gain was found in North Dakota, up nearly 11% from last June. Neighboring Minnesota, however, had the second-largest year-over-year drop, down over 4%. New Hampshire had the third-largest gain of any state, up nearly 9% from last year, while neighboring Vermont had one of the largest declines, down 2%. Other states that were down from last year, such as Washington, California, New Mexico, and Maryland, were surrounded by states up from last year. In total, 35 states and the District of Columbia were higher and 15 states lower relative to one year ago.
Cooling Degree Day (CDD) trends were more regionally consistent than retail sales volume trends during the month of June. New England and New York, the Great Lakes region and Texas and New Mexico, all had lower to much-lower levels of CDDs compared to last year. The Mid-Atlantic, Southeast, and West (besides New Mexico), had uniformly higher levels of CDDs in June. States in the Northwest all had CDD increases in excess of 200% compared to last year and many of those states experienced their hottest June on record.
In relation to a "normal" June, the weather this year was much warmer than normal across most of the country. All states outside of New England, the Great Lakes, New York, Iowa, and Nebraska had elevated levels of CDDs. Nearly half of the states, 24, had CDD levels more than 25% higher than an average June.
Resource Use: June 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
Net generation in the United States increased 0.9% compared to June 2014. At the regional level, the Southeast, Florida, and Texas saw net generation increase by 3.7%, 5.5%, and 2.0%, respectively. The Northeast and Mid-Atlantic regions both saw a decrease in net generation compared to last June, as most States in the Northeast experienced temperatures that were cooler than June 2014. Some Mid-Atlantic region states are warmers while others are cooler than last year. The net result is slightly lower demand for electricity. The Central and West regions both saw net generation stay relatively unchanged compared to last year, with the Central region only experiencing a 0.3% increase and the West region seeing a 0.1% decrease from the previous year.
Electricity generation from coal decreased in all regions of the country, except for the West, where coal generation increased by 4.1% compared to June 2014. Electricity generation from natural gas increased in all parts of the country, except for the Northeast, where cooler temperatures compared to the previous year decreased the demand for electricity.
Total electricity generation from nuclear in the U.S. was up 0.6% compared to the previous June. The only region that experienced a significant decrease in nuclear generation was the West, as the Columbia nuclear plant was offline for a refueling outage during June 2015. The Western region also experienced a significant decrease in hydroelectric generation compared to the previous year, with electricity generation from conventional hydroelectric generators decreasing by 32.5% due to well below average rainfall experienced during June 2015.
Fossil fuel consumption by region
The chart above compares coal consumption in June 2014 and June 2015 by region and shows that changes in coal consumption for electricity generation were similar to changes seen in electricity generation from coal.
The second tab compares natural gas consumption by region and shows that all regions of the country, except for the Northeast, 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 June 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 decreased from the previous month, going from $2.91/MMBtu in May 2015 to $2.85/MMBtu in June 2015. The natural gas price for New York City (Transco Zone 6 NY) also saw a decrease from the previous month, going from $2.67/MMBtu in May 2015 to $2.38/MMBtu in June 2015.
The New York Harbor residual oil price decreased from the previous month, going from $10.18/MMBtu in May 2015 to $9.81/MMBtu in June 2015. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.
A fuel price comparison based on equivalent energy content ($/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 sixth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis, and the spread between the two prices widened slightly due to the month-to-month decrease in the price of natural gas at Henry Hub. Likewise, the spread between the New York City gas price and the price of Central Appalachian coal also decreased compared to the previous month, also a result of a decrease 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: June 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 electricity prices remained lower than the higher levels of electricity demand that occurred in June would suggest. This is a result, as is often the case, of low natural gas prices during the month. Natural gas prices set annual lows in five of the ten selected hubs and were within $0.15/MMBtu of annual lows in the other five selected hubs. Prices reached as low as $1.15/MMBtu in the Mid-Atlantic (Tetco M-3), $1.20/MMBtu in New England (Algonquin), $1.38/MMBtu in New York City (Transco Z6 NY), and $1.50/MMBtu in the Northwest (Sumas). Only four locations had natural gas prices exceed $3/MMBtu on any one day during June, with the high price for the month reaching just $3.24/MMBtu in Northern CA (PG&E Citygate).
As a result of these low wholesale natural gas prices, wholesale electricity prices remained well below highs recorded in the last 12 months in all regions except the West, where many states experienced their hottest June on record, even though daily peak demand levels approached 12-month high levels in nearly all regions. The highest price in June, and a 12-month high for this hub at just under $65/MWh, was found in the Northwest (Mid-C), a real anomaly as this region typically has some of the lowest prices in the country. Prices were high as a result of lower availability of hydroelectric generators due to significantly below average rainfall during them month, a planned maintenance and refueling outage in May and June at the Columbia Generating Facility (a large nuclear facility in Washington), as well as a precipitous drop in wind generation in the Pacific Northwest, which saw very little wind generation during the last week in June. This lead to a large spike in natural gas usage as natural gas-fired generation stepped in to replace the gap left by the lack of wind and nuclear generation. A 12-month high price was also set in Northern CA (CAISO) at just over $63/MWh. Contrast this with prices in much of the rest of the country, which peaked at only $32/MWh in Texas (ERCOT), $35/MWh in Louisiana (Entergy) and New England (ISONE), and $36/MWh in the Midwest (MISO). Price levels overall were fairly low compared to many previous June's.
Electricity system daily peak demand
June electricity daily peak demand was uniformly toward the upper end of the 12-month range across the country. Every region except New England (ISONE) and the Northwest (Bonneville Power Administration) had daily demand peaks over 90% of 12-month highs in their respective regions. Relative to all-time peak demand levels, Tucson Electric (94% of all-time peak), Southern Company (91% of all-time peak) and Texas (ERCOT, 90% of all-time peak), all exceeded 90% of all-time peak daily demand at some point during the month. These demand levels reflect weather patterns during the month, as most states from coast to coast (outside of New England and the Great Lakes region) recorded a very warm June.
Electric Power Sector Coal Stocks: June 2015
In June, U.S. coal stockpiles decreased to 168 million tons, down 4% from the previous month. This decrease in May-to-June coal stockpiles follows the normal seasonal pattern whereby coal stockpiles begin to decrease as the U.S. enters 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 declined slightly from 74 days to 73 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 had a much larger decrease, going from 71 days in May to 65 days in June. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn increased from the previous month, going from 5.3% in May to 9.2% in June. This is a much lower percentage than last June, when almost 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)
|June 2015||June 2014||May 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|
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.