U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for March 2013 | Release Date: May 21, 2013 | Next Release Date: June 21, 2013
Highlights: March 2013
- Net generation in the United States increased 5.3 percent compared to March 2012, mainly due to record warm temperatures in March 2012 and more average temperatures in March 2013.
- The natural gas price for New York City (Transco Zone 6 NY) dropped dramatically from the previous two months where the price averaged above $10.00 / MMBtu in January and February.
- Wholesale electricity prices remained below $60/MWh for most of the country for most of March, though prices in New England and New York went through large upswings throughout the month.
|March 2013||% Change from March 2012|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
Increased rainfall in April in the Northwest led to brief surge in hydroelectric output
Water flow levels in the Pacific Northwest, an area with a high concentration of hydroelectric capacity, have been normal this spring after initial expectations of an abundant supply of water for power generation. Hydroelectric output on the system of the Bonneville Power Administration (BPA), which operates the largest electric system in the region, were near or below the five year average for much of the year, only to surge above normal after significant rainfall in the second half of April.
Source: U.S. Energy Information Administration based on Bonneville Power Administration
Dispatch decisions for hydroelectric units reflect a complex process of gauging reservoir levels, current precipitation volumes, forecasting precipitation for the rest of the season, snowmelt and runoff from across a watershed, as well as environmental concerns for fish populations and electric system demand balance. Because of this, precipitation and meteorological forecasts influence the overall volume and timing of hydroelectric generation.
A combination of wet, warm weather led to an increase in the hydroelectric output in this region from October of 2012 to the beginning of January of this year, leading some of the early projections for the 2013 water year to be quite strong. However, in February and March of 2013, dry weather has lowered the water flow levels at major rivers in the basin. This, in combination with slightly below normal levels of snowpack, have lowered the projections for water runoff in the Northwest.Click on map to see monthly maps
Water flows at The Dalles, a centrally located run-of-river dam in the Pacific Northwest, have been trending in the normal range until increasing rapidly with rainfall in the latter half of April. These runoff levels directly affect the output from generators located at run-of-river dams on BPA's system, which also includes several reservoir dams that use the complex dispatch decisions outlined above.
Source: Source: U.S. Energy Information Administration based on U.S. Geological Survey and the University of Washington Columbia River Data Access system
The variable cost of producing electricity from hydroelectric capacity is minimal because there is no fuel cost. Consequently, when the water flow is available to generate large amounts of hydro power, wholesale electricity prices drop. Wholesale power prices at Mid-Columbia, a large trading hub for wholesale electricity in the region, are more than double the level of last spring (March through May) when hydroelectric volumes were higher.
Source: U.S. Energy Information Administration based on SNL Energy
Absent the buffer of a robust water year, the wholesale power prices have increased along with the price of natural gas. Consumption of natural gas for power has increased about 240 million cubic feet per day over the levels seen last spring while spot natural gas prices have also increased about 87% from the ten-year lows of the spring of 2012.
Source: U.S. Energy Information Administration based on Bentek Energy LLC
Principal Contributor: Tyson Brown
End Use: March 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
Compared to March 2012, the average cost of electricity increased in a majority of States across the country. The two largest increases in average retail revenue were in Rhode Island and Louisiana, where average revenues increased 10.8 percent and 15.7 percent, respectively. These are some of the largest year-over-year increases we've seen since September of last year. The largest decrease in average revenues occurred in Illinois, where prices decreased by 8.1 percent. On the whole, average revenues across the country increased 1.4 percent from last year to 9.69 cents per kilowatthour. 24 States saw average revenues increase by more than 3 percent compared to March 2012.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector March 2013 Change from March 2012 March 2013 Change from March 2012 Year to Date Residential 11.59 -1.1% 111,822 12.8% 355,943 Commercial 9.99 1.1% 103,963 2.0% 312,142 Industrial 6.59 1.7% 78,079 -3.5% 230,634 Transportation 10.20 3.8% 631 2.0% 1,941 Total 9.69 1.4% 294,496 4.2% 900,661
Source: U.S. Energy Information Administration
The average cost of electricity rose in all sectors except the Residential sector compared to March 2012, with the Transportation sector leading the change with a 3.8-percent increase to 10.2 cents per kilowatthour. The average cost of electricity in the Residential sectors fell 1.1 percent, while the average cost in the Commercial and Industrial sectors rose by less than 2 percent. Retail sales of electricity in the Residential sector appear to be following a weather-driven trend upwards, with increases over March 2012 of 12.8 percent, mostly in States that experienced a cooler March than last year and the 30-year normal. Sales in the Industrial sector dropped off 3.5 percent from last year, while Transportation and Commercial sales increased by 2.0 percent each. Year-over-year industrial sales have been decreasing in recent months. Total retail sales across all sectors increased by 4.2 percent from last March, driven mostly by the increase in sales in the Residential sector.
The map below of percent change in heating degree days (HDDs) shows colder weather in March 2013 for much of the country than in March 2012, especially in areas surrounding the Mississippi River and in the Southeast. There was a general increase in retail sales across most of the States that had cooler-than-normal temperatures this March as people consumed electricity to heat their homes and businesses. Temperatures on the West Coast were warmer both than last year and the 30-year normal. This lead to a decrease in retail sales of electricity in States on the West Coast. There has been a continued trend of year-over-year increases in retail sales in North Dakota, which seems to be driven more by population growth and increasing economic activity, rather than by changes in weather patterns.
Resource Use: March 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
Net generation in the United States increased 5.3 percent compared to March 2012. The large increase in year-over-year generation was caused by record warm temperatures in March 2012, which led to a decreased need for electricity generation during that month. Temperatures in March 2013 were much closer to average, if not slightly below normal. The Southeast, Central, and MidAtlantic regions experienced the largest increases in generation compared to March 2012, as these regions saw the largest changes in temperatures from March 2012 to March 2013. For the second month in a row, all regions of the country saw an increase in electricity generation from coal except for Florida. Of the larger coal plants in Florida, Big Bend and Crystal River saw significant declines in generation from March 2012 to March 2013. Continuing the trend seen in 2013, the Northeast region had a significant increase in percentage year-over-year coal generation, while natural gas generation in the region decreased. This occurred because natural gas prices in the Northeast were significantly higher than last year. Other parts of the country, except for Florida and the Southeast, witnessed a similar trend of natural gas generation being displaced by coal generation. The West experienced a significant decrease in hydro generation, which is discussed in greater detail in the feature article of this report.
Fossil Fuel Consumption by Region
Mirroring the change in coal generation, the chart above shows that coal consumption increased in all parts of the country, except for Florida, with the Northeast experiencing the largest year-over-year percentage increase.
The second tab compares natural gas consumption in March 2012 and March 2013 by region. Again, this consumption mirrored the changes in natural gas generation, with all regions of the country, except for the Southeast, 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. Coal increased its share of total fossil fuel consumption in all regions of the country at the expense of natural gas. In Florida, other fossil fuels (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 March 2012 and March 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 all regions of the country except for Florida and the Southeast.
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. In March 2013, the price of Henry Hub natural gas increased 14.5 percent from the previous month to $3.95 / MMBtu. The natural gas price for New York City (Transco Zone 6 NY) dropped dramatically from the previous two months when the price averaged above $10.00 / MMBtu. The large increases in this regional natural gas price are not uncommon during the winter months due to high demand for natural gas in an area of the country where the natural gas pipeline infrastructure is subject to significant congestion. The price of Central Appalachian coal decreased for the second consecutive month to average $2.79 / MMBtu in March 2013.
The average price of residual oil priced at New York Harbor decreased 13.2 percent from the previous month, going from $21.78 / MMBtu in February 2013 to $18.90 / MMBtu in March 2013. However, due to the significant drop in the New York City natural gas price, oil was once again priced out of the market in this region.
A fuel price comparison based on equivalent energy content ($/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 first time in over a year, this comparison shows that the average March 2013 price in $/MWh for Central Appalachian coal is lower than the price of natural gas at Henry Hub.
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: March 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.
Wholesale electricity prices remained below $65/MWh for most of the country for most of March, though prices in New England and New York went through large upswings throughout the month. Prices in New England peaked on March 21, when they reached $94/MWh, and were elevated above $50/MWh for most of the month. Though not quite as elevated, prices in New York remained generally between $50 and $70 per MWh for much of the month. Towards the end of the month, prices at these two hubs fell back to levels relatively close to those of the other hubs, though they still remained slightly higher than the others.
Natural gas prices in New England were elevated and volatile for much of March. New England reached a monthly high on March 21, with prices reaching $11.54/MMBtu. It is clear from the data that large spikes in natural gas prices in New England translated into similarly elevated wholesale electricity prices in the corresponding electricity market. The New York City price was slightly elevated in March. The natural gas prices at the remaining hubs were relatively stable all month, generally hovering around the average Henry Hub price of $3.95/MMBtu. They also set annual prices highs.
Electricity System Daily Peak Demand
The monthly range of daily peak-hour demand as a percentage of all-time peak demand for March 2013 compared to the annual range varied from region to region, showing light demand across the electrical systems. No system posted a monthly-high peak load above 80 percent of its all-time peak demand during the month of March. Only Southern Company, Progress Florida and BPA reached peak demands above 70 percent of their all-time peaks. Only Progress Florida reported a peak demand as high as 75 percent of its all-time peak demand, but it also posted the lowest demand of all the systems as a fraction of its all-time peak down around 40 percent. Both Southern Company and Bonneville Power Administration nearly posted annual low peak demands. Most of the systems recorded demand that was generally between 50 percent and 70 percent of their all-time highs for the month of March. Since March is a shoulder period for much of the country as we come out of the winter months, it is unsurprising that there was not much high demand in any of the systems.
Electric Power Sector Coal Stocks: March 2013
In March 2013, total coal stocks decreased 2.2 percent from the previous month, indicating increased consumption of coal due to a combination of colder weather, lower prices for coal, and higher natural gas prices in many regions. Total coal stockpiles were around 173 million tons, the lowest total level since December of 2011 and a 4 percent drop since the beginning of the year.
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. As with total stockpile levels, the days of burn held at electric power plants are decreasing, but remain at elevated levels. In March 2013, total bituminous supply decreased from 96 days the previous month to 88 days. Total subbituminous supply decreased from 85 days of burn in February 2013 to 79 days of burn in March 2013.
Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)
|March 2013||March 2012||February 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.