End Use: February 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 February 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 12.9 percent and 11.8 percent, respectively. These are the largest year-over-year increases we've seen since September of last year. The two largest decreases in average revenues occurred in Illinois and Nevada, where prices decreased by 6.7 percent and 5.3 percent, respectively. On the whole, average revenues across the country increased 1.8 percent from last year to 9.77 cents per kilowatthour. 20 States saw average revenues increase by more than 3 percent compared to February 2012.

The average cost of electricity rose in all sectors compared to February 2012, with the Transportation sector leading the change with a 5.9-percent increase to 10.11 cents per kilowatthour. The average cost of electricity in the Residential and Commercial sectors rose just 0.8 percent. Retail sales of electricity in the Residential sector appear to be following a weather-driven trend upwards, with increases over February 2012 of 4.6 percent. Sales in the Industrial sector dropped off 4.5 percent from last year, while Transportation sales increased by just 0.1 percent. Year-over-year industrial sales have been decreasing in recent months, but the 4.5-percent decline this month was the largest. Total retail sales across all sectors increased by just 0.9 percent from last February.

Retail Sales

As seen in the map below of percent change in heating degree days (HDDs), February 2013 was colder for much of the country than in February 2012, especially in areas east of the Mississippi River. This lead to an increase in Residential and Commercial retail sales of electricity as people consumed electricity to heat their homes and businesses. In the Northwest, temperatures were warmer than they were last February, and there was a corresponding decrease in electric sales in that region over the same period. There has been a continued trend of year-over-year increases in retail sales in the Dakotas, particularly North Dakota, that seems to be driven more by population growth and increasing economic activity, rather than by changes in weather patterns.

 

Resource Use: February 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 generator type and fuel 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 remained relatively flat compared to February 2012, only decreasing by 0.2 percent compared to the previous year. Only the Central and MidAtlantic regions had sizable increases in total net generation compared to February 2012. This occurred because both regions had a much warmer February in 2012, which lead to an increased demand for electricity generation in February 2013. Except for Florida, all regions of the country saw an increase in electricity generation from coal. The decline in coal generation in Florida was mainly due to a decrease in electricity generation from coal at the Big Bend coal plant. In February 2012, Big Bend had significantly increased its electricity generation from coal, making up 32 percent of coal generation in Florida. In February 2013, Big Bend made up 15 percent of the coal generation in Florida, which is much closer to its historical average. Like last month, the Northeast region had the largest percentage year-over-year increase in coal generation, while electricity generation from natural gas saw a significant year-over-year decrease. This occurred because, for the second straight month, natural gas prices in the Northeast were significantly higher than last year. Other parts of the country, except for Florida, witnessed a similar trend of natural gas generation being displaced by coal generation. Nuclear generation decreased from February 2012 in all parts of the country, mainly due to an increased number of nuclear plants that were offline for maintenance in February 2013.

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 and Texas, with the Northeast experiencing the largest year-over-year percentage increase.

The second tab compares natural gas consumption in February 2012 and February 2013 by region. Again, this consumption mirrored the changes in natural gas generation, with all regions of the country, except for Florida, 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 except for in Florida. This third tab also shows that, for a second straight month, other fossil fuel consumption increased in the Northeast region due to the increased price of natural gas.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis between February 2012 and February 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.

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 February 2013, the price of Henry Hub natural gas remained flat from the previous month at $3.45 / MMBtu. However, the natural gas price for New York City (Transco Zone 6 NY) remained high for the second straight month, going from $10.36 / MMBtu in January 2013 to $10.46 / MMBtu in February 2013. This increase was mainly due to spikes in daily spot prices that occurred during the month as a result of a cold snap that affected the Northeast region during February 2013. The natural gas price for New York City has often spiked during the winter months, since demand for natural gas increases during this time of the year in an area of the country where the natural gas pipeline infrastructure is subject to significant congestion. Over the same time period, the price of Central Appalachian coal decreased from the previous month to $2.88 / MMBtu.

For the second straight month, the average price of residual oil priced at New York Harbor increased from the previous month, going from $19.48 / MMBtu in January 2013 to $21.78 / MMBtu in February 2013. As seen in the previous month, albeit to a lesser extent, February 2013 was also another rare occasion when oil was not entirely priced out of the electricity market, due to the spikes in the daily spot natural gas prices in the Northeast.

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. This comparison shows that the average February 2013 price in $/MWh for Central Appalachian coal is higher than the price of natural gas at Henry Hub, as it has been for over a year now. However, the gap between the two narrowed from January 2013 to February 2013, due to a decrease in the price for Central Appalachian coal. The Transco Zone 6 NY natural gas price rose significantly above the Henry Hub gas and Central Appalachian coal prices in February 2013 which, as stated previously, indicates significant congestion on the natural gas pipelines serving New York City.

The conversion shown in this chart is done for illustrative purposes only. The competition between coal and natural gas to produce electricity is more complex. It involves delivered prices and emission costs, the terms of fuel supply contracts and the workings of fuel markets.

 

Regional Wholesale Markets: February 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 Prices

Wholesale electricity prices remained below $50/MWh for most of the country for most of February, though prices in New England and New York went through large upswings in the first three weeks of the month. Prices in New England peaked on February 12, when they reached nearly $270/MWh, and were above $100/MWh for the whole month until February 22. Though not quite as elevated, prices in New York remained generally between $100 and $150 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 exhibited a very similar trend to the electricity prices. Most of the hubs remained relatively stable all month, generally hovering around the average Henry Hub price of $3.45/MMBtu. However, prices in New England and New York were also elevated and volatile for much of February. Both hubs reached monthly peaks on February 11, with prices in New York hitting $19.72/MMBtu and those in New England reaching $30.89/MMBtu. It is clear from the data that very large spikes in natural gas prices in these three regions translated into similarly elevated wholesale electricity prices in their corresponding electricity markets. These prices were so high that the effects can be seen in the Resource Use section under Net Generation by Fuel Type. In New England, natural gas accounted for a significantly smaller percentage of electricity generation this February than last, with the slack being picked up by increased generation from coal and petroleum consumption.

Electricity System Daily Peak Demand

The monthly range of daily peak-hour demand as a percentage of all-time peak demand for February 2013 compared to the annual range varied from region to region, though there wasn't much heavy 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 February. Only Progress Florida reported a peak demand above 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. Both Progress Florida and ERCOT Texas 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 February. The peak demand in Progress Florida's system occurred on February 18, which corresponded to unusually low temperatures on that day. Electricity accounts for a significant portion of space heating demand in Florida, so it appears this peak demand was caused by residents reacting to the lower temperatures with increased consumption of electricity.

 

Electric Power Sector Coal Stocks: February 2013

 

In February 2013, total coal stocks decreased 1.7 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 177 million tons, the lowest total level since August of 2012 but still high for a winter month when stockpile levels typically fall due to increased consumption to meet heating demand.

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 remained at elevated levels. In February 2013, total bituminous supply remained flat from the previous month at 96 days. Total subbituminous supply increased from 80 days of burn in January 2013 to 85 days of burn in February 2013.

Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)

		February 2013			February 2012			January 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
Northeast	Bituminous	7,040	76		9,253	86	-23.9%	7,414	71	-5.0%
	Subbituminous	251	52		661	76	-61.9%	448	51	-43.9%
South	Bituminous	49,164	103		50,413	99	-2.5%	49,894	105	-1.5%
	Subbituminous	6,732	77		7,917	81	-15.0%	6,610	76	1.8%
Midwest	Bituminous	15,710	78		17,017	79	-7.7%	16,047	74	-2.1%
	Subbituminous	42,310	78		47,772	80	-11.4%	43,723	74	-3.2%
West	Bituminous	6,586	127		6,888	126	-4.4%	7,176	138	-8.2%
	Subbituminous	34,073	97		31,381	88	8.6%	33,380	92	2.1%
U.S. Total	Bituminous	78,500	96		83,571	95	-6.1%	80,531	96	-2.5%
	Subbituminous	83,365	85		87,730	83	-5.0%	84,161	80	-0.9%

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

General

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.

Key Indicators

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.

Sector Definitions

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

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.