U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for April 2014 | Release Date: June 23, 2014 | Next Release Date: July 25, 2014 | Revision
Highlights: April 2014
- Nearly all states had an increase in their retail price for electricity in April. Only California, West Virginia, and Montana decreased from last year.
- Many wholesale electricity prices and demand levels were near 12-month lows during the month of April.
- Total U.S. coal stocks are down 25.7 percent compared to last April.
|April 2014||% Change from April 2013|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Commercial and industrial retail choice programs continue to grow in eight statesSource: EIA-861, Annual Electric Power Industry Report.
State retail electricity choice in the commercial and industrial sectors has grown significantly in eight states since 2009. Almost half of the U.S. states allow industrial and commercial electricity customers to choose a supplier other than their traditional utility. This growth in retail choice among commercial/industrial customers mirrors a similar trend among residential customers.
Currently, 19 states (revised from 23 in the original June 23, 2014 article) and the District of Columbia have retail choice programs for commercial and industrial customers. Eight states, mostly in the Northeast, have become clear-cut leaders in commercial/industrial retail choice as measured by participation rates. Those states -- Connecticut, Illinois, Massachusetts, Maryland, New Jersey, New York, Ohio and Pennsylvania -- have shown a significant rise in commercial/industrial customer participation. Those states have voluntary retail choice programs, i.e., customers can choose to buy from a competitive retail supplier or continue to receive service from their traditional utility.
Texas data were not included in this report. Texas's retail choice program is mandatory under state law. Retail customers must either choose a competitive supplier or be assigned one in the part of the state where the electric system is operated by the ERCOT regional transmission organization.
In 2012, the leading states for participation in retail choice in the commercial and industrial sectors were Connecticut (49%) and Ohio (44%), with Maryland and Pennsylvania tied for third place at 38% each. These states all had the fastest rise in the percent of customers switching to competitive suppliers in the period from 2009-12. In contrast, New York and Massachusetts each had a relatively higher percentage of participation at the beginning of the 2009-12 period, at 23%. In 2012 they only showed a modest growth: Massachusetts to 27% and New York to about 30%.
While the data in this report indicate an upward trend in switching from traditional utility-bundled service to competitive rates offered by power marketers, it may inhibit the growth in retail choice programs. The extreme cold temperatures during the winter of 2013-14 and at the same time increases in wholesale electricity and natural gas prices, have led some retail customers that experienced this price volatility to complain to their state Public Utility Commissions (PUC) or Public Service Commission (PSC). Recently, the New York PSC had been formally asked by a state senator to look into the price spikes in response to hundreds of complaints by customers. The Pennsylvania PUC, meanwhile, has issued rule changes to address wide fluctuations on the variable rates in the electric market there. The Maryland PSC is revising rules for retail customers to protect them from service disconnection and to allow them to more easily switch providers. As a result of these market/weather developments, customers, at least in the short term, may seek retail choice contracts with more price certainty and less risk.
End Use: April 2014
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
In April, nearly all states had higher average revenue per kWh figures compared to last April. Rhode Island had the highest year-over-year average revenue per kWh increase at just over 21%, followed by Kentucky, up nearly 14%, Louisiana, up almost 12%, and Massachusetts, up just over 10%.
California, West Virginia and Montana were the only states to have lower average revenue per kWh figures compared to last April, with Vermont and Arizona both flat. California had by far the largest decrease at over 11% from last year. West Virginia had a year-over-year decrease of close to 4%, and Montana was down almost 2%.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector April 2014 Change from April 2013 April 2014 Change from April 2013 Year to Date Residential 12.31 3.2% 92,188 -3.3% 483,259 Commercial 10.40 4.4% 102,403 1.0% 428,168 Industrial 6.75 3.4% 77,638 0.0% 306,470 Transportation 10.06 1.1% 634 1.8% 2,726 Total 10.01 3.5% 272,863 -0.8% 1,220,622
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour averaged 10.01 cents in April, 3.5% higher than April 2013, though down from 10.32 cents in March. All sectors increased, with the commercial sector up 4.4% to 10.4 cents per kilowatthour, the industrial sector up 3.4% to 6.75 cents per kilowatthour, the residential sector up 3.2% to 12.31 cents per kilowatthour, and the transportation sector up 1.1% to 10.06 cents per kilowatthour.
Total retail sales volumes decreased 0.8% from last April, totaling 272,863 GWh based on a large drop in the residential sector. Weather sensitive residential volumes fell 3.3% this April from last year, totaling 92,188 GWh. The other sectors were either up for the month, with the transportation sector up 1.8% to 634 GWh and the commercial sector up 1% to 102,403 GWh, or flat, as the industrial sector remained at roughly 77,638 GWh in April.
Similar to last month, electric industry retail sales volume trends varied widely state-by-state and across regions. The largest volume increase was found in an upper Midwestern state, with North Dakota up 8.7% from last April, likely on the back of increased economic activity. Retail sales were also up in the Mid-Atlantic, with the District of Columbia up just over 8% and in Northeastern states, with New Jersey up 4.6% and Maine up 4.2%. California and Utah retail sales were up almost 3%.
As has been the case for many months, Kentucky had the largest decrease of any state, down over 20%, as the closure of a large energy consumer last year, the United States Enrichment Corporation facility in Paducah, Kentucky, continues to affect year-over-year comparisons. Illinois and Missouri were also down more than 5% this April when compared to a year ago.
Heating degree days (HDDs) were down this April across most of the country when compared to one year ago. Louisiana, down 32%, and Texas, down 31%, had the greatest declines. Kentucky, Oklahoma, Kansas and Alaska also had HDD declines greater than 25%.
On the opposite end of the spectrum, Florida had an HDD increase of 23%, though that number is exaggerated due to the very small number of HDDs that typically occur in Florida in April. The District of Columbia, up 14%, and Delaware, up 11%, had the next highest levels of HDD increases in April compared to last year.
HDD comparisons to long-term normal levels this month show continued cold weather in the upper Midwest, which dealt with one of the coldest winters on record. Although, April 2013 was cooler than this April. The four states with the greatest increase in HDDs from normal in April were, in order: Minnesota, North Dakota, Wisconsin and Iowa. The greatest decreases in HDD levels from normal were found clustered in the Southwest (Nevada and Arizona) and California, and in the region around Ohio, Kentucky and West Virginia.
Resource Use: April 2014
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 April 2014, net generation in the United States decreased by 0.4 percent compared to April 2013. This slight decrease in electricity generation follows the year over year decrease of 3.8 percent in total heating degree days when April 2013 is compared to April 2014 (see the heating degree day map on the End Use page).
At the region-level, changes in electricity generation from the previous year were mixed. The Northeast, Southeast, Central, and West all saw decreases in electricity generation compared to April 2013, while the Mid-Atlantic, Florida, and Texas all saw increases in electricity generation.
Compared to the previous April, the only regions that saw a significant decrease in electricity generation from coal were the Central and West regions. The change in natural gas generation was more varied, with the West, Texas, and Florida all seeing increases in electricity generation from natural gas compared to April 2013. The Northeast, Mid-Atlantic, Central, and Southeast all saw decreases in natural gas generation.
Total electricity generation from hydroelectric generators in the U.S. increased compared to last April. Electricity generation from other renewables increased in all parts of the country, with the largest change from last April coming from an increase in the use of wind and solar.
Fossil fuel consumption by region
The chart above shows that the change in total coal consumption mostly mirrored the change in electricity generation from coal in each region.
The second tab compares natural gas consumption in April 2013 and April 2014 by region. This consumption pattern mirrored the change in electricity generation from natural gas, with the Central region having the largest percent decrease in natural gas consumption and Florida having the largest percentage increase.
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. Coal increased its share of total fossil fuel consumption in all parts of the country except for the West and Florida, where natural gas gained a bigger share of fossil fuel consumption compared to last April.
The fourth tab presents the change in coal and natural gas consumption on an energy content basis between April 2013 and April 2014 by region. Once again, 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 second consecutive month, the price of natural gas at Henry Hub decreased from the previous month, going from $4.91 / MMBtu in March 2014 to $4.78 / MMBtu in April 2014. The natural gas price for New York City (Transco Zone 6 NY) decreased significantly from the previous month, going from $7.97 / MMBtu in March 2014 to $4.26 / MMBtu in April 2014.
For the second consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $19.57 / MMBtu in March 2014 to $18.60 / MMBtu in April 2014. Now that natural gas prices have decreased significantly since the winter months, oil used as a fuel for electricity generation is now almost always priced out of the market.
A fuel price comparison based on equivalent energy content ($ / MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. The spread between the Henry Hub natural gas price and the price of Central Appalachian coal on a $ / MWh basis remained relatively the same compared to last month. However, because of the continued decrease in the New York City natural gas price, the spread between the price of Central Appalachian coal and the New York City natural gas price narrowed even further compared to last month.
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 2014
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.
Daily wholesale electricity and natural gas prices traded in narrow bands towards the bottom of yearly ranges in April. Prices in the Northeast and Mid-Atlantic topped out at just $66/MWh in New England (ISONE), $62/MWh in New York City (NYISO) and $61/MWh in PJM, a far cry from the high prices experienced this past winter. Interestingly, the highest prices in April were found in Louisiana (into Entergy), which reached $88/MWh on April 16 when record low temperatures, some 20 degrees below normal, spread across much of the state. Prices promptly dropped the next day as temperatures rebounded. In the Northwest, prices at Mid-C reached an annual low of $14/MWh, not uncommon for this time of year due to a combination of mild spring weather keeping a lid on demand and increased hydroelectric production as snowpack begins to melt.
Daily wholesale natural gas prices traded in a tight range during the month of April, with less than a $0.50/MMBtu difference between the high and low prices for the month at all locations except New England (Algonquin), New York City (Transco Z6 NY) and Mid-Atlantic (Tetco M-3). Prices were elevated slightly mid-month at those three locations, with the highest prices of $6.80/MMBtu at New England (Algonquin) on April 16 due to a quick burst of cold weather pushing low temperatures below freezing that day, though nothing like the weather and prices seen in previous months.
Electricity system daily peak demand
Daily peak electricity system demand levels were generally lower in April than they were in March. Both New York State (NYISO) and Progress Florida recorded peak days that were the lowest in the last twelve months. New England (ISONE), Mid-Atlantic (PJM), Southern Company, Texas (ERCOT) and Tucson Electric all had days where peak loads were very close to the low for the last twelve months. In New England (ISONE) and New York State (NYISO), peak loads were low enough to not exceed 60% of all-time peak throughout the month.
The only areas with slightly elevated peak load levels above 70% of all-time peak were Progress Florida and Texas (ERCOT), where short periods of hot weather increased electricity demand. In Progress Florida, peak demand occurred on April 27, as a high temperature of 90 degrees was just one degree shy of the all-time record for the day (as measured in Orlando). System demand exceeded 9.5 GW on that day, a high for the month but far below the 13.4 GW all-time peak. In Texas (ERCOT), temperatures well into the 90's across much of the state drove up electricity demand towards the end of the month, leading to system demand of 48.5 GW on April 28, though still far below the 68.4 all-time record peak demand.
Electric Power Sector Coal Stocks: April 2014
Total U.S. coal stocks increased by 10.3 million tons compared to the previous month as the electric industry begins its spring build-up of coal stocks at power plants. However, compared to the previous April, total U.S. coal stocks are down 25.7 percent.
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. The total bituminous supply decreased from 57 days the previous month to 55 days in April 2014, while the total subbituminous supply remained flat at 50 days of burn.
Coal stocks and average number of days of burn for non-lignite coal by region (electric power sector)
|April 2014||April 2013||March 2014|
|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 is proprietary and non-public.
The Key Indicators 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, Cooling 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.
Cooling Degree Days: Reflects the total population weighted U.S. 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. This data is 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 (IPP), including IPP plants that operate as CHP). 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 unit 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 primary fuel of lignite and 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.
For lists of the plants included in the calculations, the plants that are excluded, and the plants that are aggregated with terminals, contact EIA at EIA923@eia.gov.
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.