U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for September 2013 | Release Date: Nov. 22, 2013 | Next Release Date: Dec. 20, 2013
Highlights: September 2013
- New England experienced a hot spell during Sept. 11 and Sept 12 that caused wholesale electricity prices to spike to $181 $/MWh and $89 $/MWh on respective days.
- For the first time in four months, the prices for natural gas at both Henry Hub and New York City on a $/MWh basis were above the price of Central Appalachian coal.
- Total coal stocks decreased 1.2 percent from the previous month, deviating from the August to September pattern observed over the past several years.
|September 2013||% Change from September 2012|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Residential Electricity Retail Choice Takes Off in Eight States after 2009
Almost half of the U. S. states allow electricity customers to voluntarily choose a supplier other than their traditional utility. These "retail choice" programs have been very popular with commercial and industrial customers. Residential customers have been reluctant to switch to competitive retail suppliers until recently. Eight states mostly in the Northeast have seen significant growth since 2009 in residential retail choice participation.Source: U.S. Energy Information Administration
Currently, 23 states and the District of Columbia in the U.S. have active retail choice programs for residential customers. In 2012, 8.2 million residential customer choices were signed up with competitive retail suppliers. This was nearly four times the 2.6 million customers signed up in 2009. However, the number of residential retail choice customers remains a very small portion of the total of residential customers in the U. S. (less than 1 percent).
We profile in this article eight states that have had recent rapid growth in retail choice participation rates. The states are Connecticut, Illinois, Massachusetts, Maryland, New Jersey, New York, Ohio and Pennsylvania. These states have voluntary retail choice programs, i.e. customers may choose to buy from a competitive retail supplier or continue to receive service from their traditional utility. In 2009, retail choice customer counts in the eight states shown in the chart above represented 73 percent of all customers voluntarily participating in retail choice programs nationwide. By 2012, that percentage had risen to 90 percent.
In 2012, the three leading states for residential retail choice participation were Connecticut (42 percent), Ohio (36 percent), and Pennsylvania (28 percent). These states also experienced the greatest expansion in participation rates since 2009 with Connecticut expanding by 32 percentage points, Ohio by 29 percentage points, and Pennsylvania by 25 percentage points. The two leading states for residential participation rates in 2009, New York (14 percent) and Massachusetts (11%), experience slower growth relative to the leading states with New York moving to 19 percent and Massachusetts to 13 percent in 2012. Given differences in the number of customers per state, the states with the most residential retail choice customers in 2012 were Ohio (1.8 million), Pennsylvania (1.5 million) and New York (1.3 million).
Unlike other states, Texas' retail choice program is mandatory under state law. Retail customers must either choose a competitive supplier or are assigned one in the part of Texas where the electric system is operated by the ERCOT Regional Transmission Organization. Not surprisingly, Texas has highest percentage of retail choice customers of any state.
Principal Contributor: Stephen Scott
End Use: September 2013
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
The average cost of electricity increased by more than 2 percent in twenty-nine states and the District of Columbia, when compared with September 2012. Sixteen states saw average revenues per kilowatthour increase by more than 5 percent compared to a year ago. The largest increases in average retail revenue per kilowatthour were reported by Rhode Island, Louisiana and Idaho, which each had gains of over 15 percent. For the second month in a row, Rhode Island reversed a multi-month trend of declining prices and posted a 21.5-percent-rise in retail revenues in September. Louisiana continued to show a trend of rising revenues with a 16 percent increase, and Idaho had a 15.5 percent rise in revenues when compared with September 2012.
There were four states that experienced declines in average revenues per kilowatthour of more than 3 percent when compared to September 2012. Illinois declined by 7.1 percent; both Delaware and West Virginia fell by 4.8 percent; and Hawaii dropped by 4.7 percent.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector September 2013 Change from September 2012 September 2013 Change from September 2012 Year to Date Residential 12.52 1.5% 121,235 1.7% 1,065,996 Commercial 10.59 0.4% 118,826 2.0% 1,012,600 Industrial 7.12 1.6% 80,360 -1.5% 720,642 Transportation 10.91 5.0% 630 0.2% 5,718 Total 10.45 1.4% 321,051 1.0% 2,804,956
Source: U.S. Energy Information Administration
Average revenues per kilowatthour increased nationally by 1.4 percent from last year, to 10.45 cents per kilowatthour. The transportation sector had the highest percentage increase in September with a 5-percent rise to 10.91 cents per kilowatthour. The average cost of electricity in the commercial sector rose only slightly by 0.4 percent. The residential and industrial sectors rose modestly from September 2012, by 1.5 percent and 1.6 percent, respectively.
Retail sales of electricity in three of the four sectors increased slightly from September 2012. Sales in the commercial sector increased the most, up 2 percent when compared to a year ago. Sales to the residential sector rose by 1.7 percent, while sales to the transportation sector were only up slightly, by 0.2 percent. Sales to the industrial sector dropped slightly by 1.5 percent.
Total retail sales across all sectors increased by 1 percent from last September.
In general, regional changes in retail sales tended to mirror regional weather patterns. Compared with August 2012, the Mid-West, the Mid-Atlantic, New England, California and Nevada had much milder weather and less electricity demand, and showed the greatest percent decrease. A similar pattern can be seen in the Southern states and the upper Mid-Western states, particularly Minnesota, Wisconsin and Iowa, which had warmer temperatures relative to a September 2012 and modest increases in retail sales.
The map below of percent change in cooling degree days (CDDs) shows how the changes in weather patterns were a significant driver in changes in retail sales.
Resource Use: September 2013
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 September 2013, net generation in the United States increased 1.6 percent compared to the previous year. This increase in electricity generation occurred because September 2013 was warmer than September 2012. Only the Northeast and West regions saw a decrease in electricity generation compared to the previous year. This occurred because in both regions, temperatures were warmer in September 2012 compared to September 2013.
All regions of the country, except for Texas, saw a decrease in electricity generation from natural gas compared to the previous year. This decrease in electricity generation from natural gas was mainly a result of the rise in natural gas prices that occurred over the past year. Conversely, coal generation increased in all parts of the country except for in the West and Northeast regions, although there was very little electricity generation from coal in the Northeast in both September 2012 and September 2013.
Hydroelectric generation increased in all parts of the country, except for in the West, where it is a predominant resource used to produce electricity. Electricity generation from wind continues to see a year-over-year increase in most regions of the country, except for Texas and the Southeast, due to increased wind capacity compared to last year.
Fossil Fuel Consumption by Region
Consistent with the trends in coal generation, the chart above shows that the change in coal consumption mostly mirrored the change in electricity generation from coal.
The second tab compares natural gas consumption in September 2012 and September 2013 by region. This consumption pattern is consistent with changes in natural gas generation, with all regions of the country, except for Texas, seeing decreases 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. Except for Texas and the West, coal increased its share of total fossil fuel consumption in all regions of the country at the expense of natural gas. For the sixth month in a row, other fossil fuels in Florida (mainly oil) also cut into natural gas's share of total fossil fuel consumption.
The fourth tab presents the change in coal and natural gas consumption on an energy content basis between September 2012 and September 2013 by region. Once again, the change in total fossil fuel use was very similar to the changes seen in total net generation in each region, with coal displacing natural gas in most regions of the country.
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 first time in four months, the price of Henry Hub natural gas increased from the previous month, going from $3.54 / MMBtu in August 2013 to $3.72 / MMBtu in September 2013. The natural gas price for New York City (Transco Zone 6 NY) showed a similar increase from the previous month, going from $3.58 / MMBtu the previous month to $3.84 / MMBtu in September 2013. The price of Central Appalachian coal had its largest month-to-month change over the past year, decreasing $0.16 / MMBtu from $2.78 / MMBtu in August 2013 to $2.62 / MMBtu in September 2013.
For the second consecutive month, the average price of residual oil priced at New York Harbor increased from the previous month, going from $17.30 / MMBtu in August 2013 to $17.59 / MMBtu in September 2013. Regardless, it remains almost always priced out of the market in the continental United States.
A fuel price comparison based on equivalent energy content ($ / 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. On a $ / MWh basis, the price of natural gas at Henry Hub remained below the price of Central Appalachian coal in July and August 2013. However, due to the significant drop in the price of Central Appalachian coal from the previous month, the price of natural gas at Henry Hub climbed above the price of Central Appalachian coal in September 2013. Additionally, the price of natural gas for New York City (Transco Zone 6 NY) is now also higher than 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: September 2013
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 prices for most of the hubs ranged between $30 and $60/MWh for most of September. On average this was equivalent to August. Three hubs, New England (ISONE), New York State (NYISO) and the Mid-Atlantic (PJM) had price spikes during a 2-day heat wave that occurred in those regions. High temperatures and high humidity caused demand to rise significantly during September 10 - 12. Boston recorded a high temperature of 97 degrees on September 11. Providence, RI and Hartford, CT both recorded temperatures in the low 90's that day. The resulting electricity demand caused the New England hub to have a price spike of $180.72/MWh on September 11. This was the highest daily wholesale electricity price throughout the country in September. The Mid-Atlantic and New York hubs had the next highest daily wholesale electricity prices of September, $103.37 and $97.32, respectively. These monthly high prices were the result of the increased demand due to the same 2-day heat wave. The Northwest (Mid-C) hub had the lowest wholesale electricity price in September, 23.50/MWh, recorded on the last day of the month.
Natural gas prices in September were higher than in August. They generally ranged between $3 and $4 per MMBtu at most hubs, again reflecting less demand due to the generally milder weather in most of the U.S. The New England Algonquin hub reported a price of $4.98/MMBtu, the highest wholesale natual gas price of the month. This was followed by PG&E Citygate and the So Cal Border hubs in California, which reached $4.14/MMBtu and $4.08/MMBtu, respectively.
Looking at the low end of the price scale, the Northwest (Sumas) hub had the lowest price of the month at $2.58/MMBtu. The next-lowest price was $3.24/MMBtu, recorded by the Southwest (EL Paso San Juan) hub.
Electricity System Daily Peak Demand
The monthly range of daily peak-hour demand as a percentage of all-time peak demand for September 2013, showed most electric systems near the middle of their all-time peak demand. Three electric systems rose toward the higher end of this range: New England (ISONE), New York State (NYISO) and Mid-Atlantic (PJM). This was due to a brief heat wave in the middle of the month which drove up demand in these highly populated areas in the eastern U.S.
Progress Florida, Texas (ERCOT), Tucson Electric and California (CAISO) also climbed to the upper middle range of their all-time peak demand levels due to warmer than normal temperatures for September in those regions of the country. The Bonneville Power Authority had daily peak-hour demand at the lower end of their range this month, due to milder weather.
Electric Power Sector Coal Stocks: September 2013
In September 2013, total coal stocks decreased 1.2 percent from the previous month. This decrease in month-to-month coal stocks deviates from the normal seasonal pattern, as there has been a slight increase in total coal stocks from August to September over the past several years. Compared to last September, coal stocks decreased 14.9 percent. This occurred because coal stocks in September 2012 were at an extremely high level.
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 slightly from 87 days the previous month to 86 days in September 2013, while the total subbituminous supply increased slightly from 63 days in August 2013 to 64 days in September 2013.
Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)
|September 2013||September 2012||August 2013|
|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.