U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for April 2015 | Release Date: June 25, 2015 | Next Release Date: July 24, 2015
Highlights: April 2015
- Florida had the largest percent increase in net generation compared to the previous year, increasing 6.4%, as the state recorded its warmest April on record.
- The natural gas price for New York City (Transco Zone 6 NY) saw a significant decrease in price from the previous month, going from $3.73/MMBtu in March 2015 to $2.30/MMBtu in April 2015.
- Hawaii had the largest year-over-year decline in average revenue per kilowatthour for the fourth straight month, down about 22% from last year, as the state's petroleum-heavy power sector continued to benefit from the fall in world oil prices.
|April 2015||% Change from April 2014|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
EIA now collects construction costs for all new electric generators
In calendar year 2014, the form EIA-860 (the Annual Electric Generator Report) began collecting unit-level construction and financing cost data for new generation units for data year 2013. The EIA-860 collects data for all utility-scale generating units at U.S. power plants where the total generator nameplate capacity is 1 megawatt (MW) or more. This is the first time that construction cost data have been collected for the census of new generators on the EIA-860. The construction costs of new generating plants play an important role in determining the mix of capacity additions that will serve future demand for electricity. All of the cost data are treated as sensitive and protected and will only be released at an aggregate level.Notes: The gray lines on the capacity-weighted average generator cost represent +/- 1 weighted standard deviation.Source: U.S. Energy Information Administration, Annual Electric Generator Report (Form EIA-860)
These cost data were collected from 543 units that collectively represent 14,038 MW of new capacity. Details of the 2013 capacity cost additions are shown below.
|Energy source||Generator count||% of total count||Summer capacity (MW)||% of total capacity|
|Notes: *Biomass: Include Other Biomass Gas, Other Biomass Solids, and Wood/Wood Waste Solids.
**Other: Include battery storage, flywheel, municipal solid waste and other gas.
Source: U.S. Energy Information Administration, Annual Electric Generator Report (Form EIA-860), 2013.
EIA is planning to integrate the new construction cost data into future issues of the Electric Power Annual. We are also exploring other ways to present this new data, which may include graphs showing the average $/kW cost by major energy sources, technology type, and census region.
Some findings by energy source include the following:
Natural Gas: The majority of capacity additions in 2013 were natural gas applications. Largely as a result of low natural gas prices and average construction costs of $953 per kilowatt (kW), natural gas units accounted for 49% of the 2013 capacity additions. Within the natural gas applications, the technology type was a significant determinant of cost. For example, natural gas- based fuel cell applications are comparatively expensive ($7,354/kW) and without the contribution of this technology, the weighted-average cost of natural gas capacity additions would have been $922/kW.
Solar: Solar accounted for 25% of the capacity additions in 2013 and almost half of the generating unit additions. The average cost of this type of application was $3,705/kW. Photovoltaic units made up 75% of the total solar capacity addition. Thermal solar applications accounted for the remaining 25%. The projects using thin-film technologies averaged $3,688/kW, and they were slightly less expensive than crystalline silicon projects, which cost $3,718/kW.
Wind: The average cost of wind applications was $1,892/kW and is the lowest of all renewable technologies. The reported new wind capacity in 2013 was less than 900 MW, a significant drop from the 13,084 MW of capacity installed in 2012.
Regional Considerations: The cost of building power plants in 2013 showed significant regional variations. For example, the cost of building a plant in the Northeast was significantly higher than in other parts of the country. There are many factors behind these regional differences including the type and size of new units installed, as well as labor, equipment, and material costs.Notes: The gray lines on the capacity-weighted average generator cost represent +/- 1 weighted standard deviation.Source: U.S. Energy Information Administration, Annual Electric Generator Report (Form EIA-860)
End Use: April 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 almost evenly split between those states higher and those lower compared to last April. Twenty-nine states were up from last year. Rhode Island (13.7%) and Massachusetts (12.2%) experienced the largest year-over-year percentage increases, as five out of the six New England states had increases relative to last April. In fact, average revenue per kilowatthour was up 9.1% in New England, the largest increase of any region. A large swath of increases also occurred in the western and central portions of the country.
Twenty-one states and the District of Columbia had average revenue per kilowatthour figures that were lower than last year. Hawaii had the largest year-over-year decline for the fourth straight month, down about 22% from last year as the state's petroleum-heavy power sector continued to benefit from the fall in world oil prices relative to last year. Louisiana had the second largest decrease with a decrease of 12%, followed by Delaware at 10%.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector April 2015 Change from April 2014 April 2015 Change from April 2014 Year to Date Residential 12.64 2.8% 89,825 -2.6% 467,262 Commercial 10.32 -1.5% 104,385 1.5% 429,172 Industrial 6.55 -2.8% 77,326 0.1% 305,114 Transportation 9.87 -1.5% 623 -2.9% 2,628 Total 10.02 -0.2% 272,159 -0.3% 1,204,176
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour were 10.02 cents in April, down 0.2% relative to last year. On balance, strong decreases in average revenues per kilowatthour in the Commercial (-1.5%) and Industrial (-2.8%) sectors overwhelmed strong increases in the Residential (2.8%) sectors to produce a reduction in total average revenues per kilowatthour.
Residential retail sales volumes were down by 2.6% compared to last April, with retail sales in the transportation sector also down (-2.9%). However, increases in the commerical sector (1.5%) and industrial sector (0.1%) caused total retail sales to be down by just 0.3% compared to last year. Also, in shoulder months, like April, residential sales volumes (89,825,000 MWh) are smaller than commercial sales volumes (104,385,000 MWh).
April 2015 sales volumes were down in 34 states and the District of Columbia relative to the same month last year. Interestingly, states that had reductions in demand were largely in a region bordered by the Midwest (Northern Plains) in the North to the Gulf Coast in the south and the mid-Atlantic seaboard in the east. The fall in demand for those regions is in accordance with weather patterns that prevailed in April 2015, which saw strong reductions in heating degree days in those areas. In areas where heating degree days were up, such as the west, demand tended to increase.
In April, total U.S. heating degree days were down around 9% relative to April 2014. As illustrated in the maps, the largest percent decreases in heating degree days centered on the Gulf Coast states, as well as the four-state region of Kansas, Missouri, Oklahoma, and Arkansas.
Resource Use: April 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 decreased 1.4% compared to April 2014. At the regional level, the Mid-Atlantic and West regions saw net generation decrease by 9.6% and 3.5%, respectively, while all other parts of the country saw net generation increase compared to April 2014. Florida had the largest percent increase in net generation compared to the previous year, increasing 6.4%, as the state recorded its warmest April on record.
For the second consecutive month, electricity generation from coal decreased in all regions of the country compared to the previous year. Electricity generation from natural gas increased in all parts of the country, except for the Northeast, where natural gas generation decreased slightly from the previous April. This slight decrease in natural gas generation observed in the Northeast can partially be attributed to the increase in nuclear generation. Specifically, the Millstone, Nine Mile Point, and Seabrook nuclear plants were offline for maintenance in April 2014, whereas all three facilities operated at full capacity in April 2015. Since nuclear plants operate as base load capacity, this decreased the need for electricity generation from natural gas plants in this shoulder month of April
Fossil fuel consumption by region
The chart above compares coal consumption in April 2014 and April 2015 by region and shows that coal consumption for electricity generation has decreased in all regions of the country.
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 April 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.
For the fifth consecutive month, the monthly average price of natural gas at Henry Hub decreased from the previous month, going from $2.87/MMBtu in March 2015 to $2.67/MMBtu in April 2015. The natural gas price for New York City (Transco Zone 6 NY) saw a significant decrease in price from the previous month, going from $3.73/MMBtu in March 2015 to $2.30/MMBtu in April 2015.
The New York Harbor residual oil price increased slightly from the previous month, going from $10.16/MMBtu in March 2015 to $10.25/MMBtu in April 2015. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.
A fuel price comparison based on equivalent energy content ($/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 fourth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. This occurred due to the decrease in the Henry Hub price beginning in December 2014. The spread between the New York City gas price and the price of Central Appalachian coal increased compared to the previous month, with the New York City gas price now below the price of Central Appalachian coal on a $/MWh basis.
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: April 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 natural gas and electricity market prices, as is generally typical of a shoulder month like April, fluctuated in the lower portion of their annual ranges. On the electricity side, the highest wholesale electricity prices prevailed in New England (ISONE), where prices peaked at $56.82 per MWh on April 8, 2015. Other regions that had wholesale electricity prices that peaked at a higher level relative to other regions include PJM ($45.22 per MWh on April 27, 2015) and Northern California (42.73 per MWh on April 30, 2015). As wholesale electricity prices generally follow wholesale natural gas price movements, it is not surprising to see natural gas prices also fluctuating in the lower portion of their ranges in April 2015. Prices peaked in New England (Algonquin) at $6.85 per MMBtu on April 8, 2015. All other wholesale market prices peaked below $3.00 per MMBtu, with the highest being Northern California at $2.95 per MMBtu on April 23, 2015.
Electricity system daily peak demand
April, as a shoulder month, tends to keep most regional electricity markets to the lower- to mid-portion of their 12-month ranges. In April, as weather warms, warmer climatic zones move higher into their 12-month ranges as the cooling season begins in those regions. While in cooler climatic zones, markets tend to move to the lower portion of their 12-month ranges, as those regions come out of their heating seasons. This pattern is illustrated by the fact that the regions with the highest percentage of all-time peak demand for April 2015 are seen in Tucson Electric (69%), Progress Florida (68%), and CAISO (68%). In terms of monthly peaks, warmer weather areas experience monthly peaks later in the month, such as CAISO and Tucson Electric on April 30, while colder climates had monthly peaks earlier in the month, such as ISONE and NYISO on April 8, 2015 and PJM on April 1, 2015.
Electric Power Sector Coal Stocks: April 2015
In April, U.S. coal stockpiles increased to 168 million tons, up 8% from the previous month. This large increase in March-to-April coal stockpiles follows the normal spring pattern where coal stockpiles are usually built up for use in the summer months. The spring build-up of coal stock piles started early this year, as the country experienced significantly above-average temperatures during the previous month, which led to a decreased demand for heating during March 2015 and thus, a decreased need for electricity generation. Coal has also lost 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 from 78 days to 76 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 decreased, going from 79 days in March to 77 days in April. The percentage of bituminous and subbituminous coal-fired capacity having less than 30 days of burn decreased in April to 5.6% from 7.9% in March. This is a much lower percentage than last April, however, when over 13% 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)
|April 2015||April 2014||March 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.