End Use: February 2012

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 rose in much of the country, except for a few States in the Northeast, the Midwest, the Gulf Coast, and California. The largest increase in revenue per kilowatthour occurred in Hawaii, at 22 %, where oil is the predominant fuel for electricity generation and where the cost of oil rose almost 27 % in the last year. Utah and Wyoming again posted average revenue increases of at least 10 %. The largest three declines were in the District of Columbia, Delaware, and Maryland which dropped between 6 and 9 % between February 2011 and February 2012.

The cost of electricity increased in the residential sector with a small increase in the commercial sector, and decreased in the other sectors. The average cost of electricity in the residential sector in February was 11.55 cents per kilowatthour. The residential sector had the largest decrease in sales at over 10%. Temperatures continued to be higher than normal in most of the country east of the Rocky Mountains driving lower demand in the residential sector. The commercial sector had virtually flat sales. The industrial and transportation sectors had slight increases in retail sales in February over the previous year.

Retail Sales

As can be seen by the map of heating degree days (HDDs), this February was very mild for most of the country. 47 States had fewer HDDs than last year, 41 had fewer than the 30-year normal. States west of the Rockies had cooler temperatures than the 30-year normal, but were still warmer than February of 2011. The State with the largest decline in HDDs was Louisiana with 30% fewer HDDs than last year. This State also reported the biggest drop in retail sales with a 10% decline. Mild weather drove a decrease in sales in the residential sector for much of the country, but particularly in States on the Gulf Coast. Many States in this region depend heavily on electricity for space heating needs, which means there is a strong correlation between electricity sales and heating demand as well as cooling demand. When temperatures are unseasonably warm in the winter months, there is often a significant decrease in electric demand in the residential sector in this region.

 

Resource Use: February 2012

Supply and Fuel Consumption

In this section, we look at what resources are used to produce electricity. Electricity supplied from the grid is consumed the moment it is produced. 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

Generation output declined in almost all regions in February due to unseasonably warm temperatures. Following the same pattern as January, fossil steam generation declined in all regions, while output from combined cycle units increased across the board. Nuclear output was mixed, down mostly due to outages in Texas and the Central and West regions. Hydroelectric output increased in all regions except the West, where this year's somewhat below normal output is compared with last year's significantly above normal output.

Natural gas generation's portion of total generation grew relative to coal-fired generation (see third tab below). This trend is likely to persist in the short term as low natural gas prices make natural gas-fired generation more economical. Wind generation in the West increased significantly from February 2011 as two large wind farms in Colorado came online in early 2011.

Fossil Fuel Consumption by Region

In tandem with the decrease in coal-fired generation, the chart above shows that coal consumption decreased in all regions except for the West, where there was a slight increase in coal consumption (and also coal generation). One of the largest drops in coal consumption was observed in the Southeast, where coal consumption decreased 29% compared to February 2011.

The second tab compares natural gas consumption in February 2011 and February 2012 by region. Consistent with the increase in natural gas-fired generation, natural gas consumption increased in all regions. The most pronounced increase was in the Mid-Atlantic region where natural gas consumption increased by 66%.

The third tab presents the change in the relative share of fossil fuel consumption on a percentage basis calculated using equivalent energy content (Btu). This highlights changes in relative consumption of coal, natural gas, and petroleum. In all regions, natural gas is replacing coal as the fuel used in electricity generation. This trend is most notable in the Southeast, Texas, Mid-Atlantic, and the Northeast regions.

The fourth tab presents the change in the relative share of fossil fuel (coal and natural gas) consumption on an energy content basis from February 2011 and February 2012 by region. This highlights changes in total fossil fuel use. The shift from coal to natural gas consumption is again most notable in the Southeast, Central, and Mid-Atlantic regions.

Fossil Fuel Prices

To gain some insight into the changing pattern of consumption of fossil fuels between February 2011 and February 2012, 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. The monthly average spot price for natural gas at Henry Hub has been below the monthly average spot price for Central Appalachian coal since December 2011. Over the first two months of 2012, the gap between these two fuel prices has only gotten larger, with Henry Hub reaching a low of $2.60 per MMBtu and Central Appalachian decreasing slightly to $3.06 per MMBtu.

The average price of residual oil continued its upward trend, increasing 16% between February 2011 and February 2012. Oil is almost always priced out of the market in the continental United States and is most often used when demand for electricity is high during abnormally hot days in the summer months.

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 2012 price in $/MWh for Central Appalachian exceeded the price of natural gas at Henry Hub for the seventh straight month. However, the average price of Transco Zone 6 New York did exceed the price of Henry Hub in February 2012.

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 2012

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 U.S. 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

The only day in February when the wholesale electricity on-peak daily spot prices reported above rose above $50/MWh was in New York City on February 13, 2012. That day was also the only day in February that any of the reported wholesale natural gas prices were above $5/MMBtu. This occurred in New York City and Boston (see the second tab).

These prices reflect cold weather demand and natural gas pipeline constraints into Northeast markets. Otherwise, daily wholesale electricity prices ranged between $29 and $42/MWh in the Northeast.

Elsewhere wholesale electricity prices stayed in the low end of the annual range except for the Northwest, which typically sees its lowest prices during the spring hydroelectric season. Annual low daily wholesale prices were set in the New England, New York, Mid-Atlantic and Southwest regions and in Louisiana, Texas and California due to unseasonably warm weather and low wholesale natural gas prices.

Wholesale natural gas prices stayed in the low end of the annual range outside of the Northeast. Annual low daily wholesale natural gas prices were set in all regions, except for the Mid-Atlantic.

Electricity System Daily Peak Demand

The monthly range of daily peak-hour demand as a percentage of all-time peak demand for February 2012 compared to the annual range varied a lot from region to region. This reflects the unusually unseasonable weather this winter. Peak demand in the Northeast, New York, Midwest, Texas, Tucson and California (CAISO) were low. And the Midwest, Texas and Tucson got close to the lowest demand during the past year. Florida (Progress Florida) saw peak demand vary in the month from almost the lowest to almost the highest for the year. The same was true to a lesser extent on the high side in the Southeast (Southern Company). The Northwest (Bonneville Power Administration) is the only place that seemed to have a normal winter range of peak demand. That is, high peak demand but not the highest of the year as in summer and not as low as the spring and fall low demand seasons.

 

Electric Power Sector Coal Stocks: February 2012

 

The unseasonably warm temperatures that the continental United States experienced throughout the winter, coupled with low natural gas prices, caused coal stocks at power plants to increase throughout the winter of 2011 - 2012. During this period, coal stocks usually see a seasonal decline due to the added need for electricity generation from coal plants for spacing heating load. However, it was the sixth straight month that coal stocks increased from the previous month, with this trend likely to continue as the country enters into spring.

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. In February 2012, total bituminous supply reached 95 days of burn, while total subbituminous supply reached 83 days of burn. These were the highest levels observed since this metric was calculated. Bituminous coal in the Western region was the only coal supply that actually had a slight decrease in days of burn when compared to the previous month.

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

		Feb 2012			Feb 2011			Jan 2012
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	9,253	86		6,076	48	52.3%	8,292	68	11.6%
	Subbituminous	661	76		385	23	71.5%	604	40	9.5%
South	Bituminous	50,428	99		42,735	79	18.0%	48,112	94	4.8%
	Subbituminous	7,917	81		4,677	48	69.2%	7,421	77	6.7%
Midwest	Bituminous	17,092	79		16,143	69	5.9%	16,390	69	4.3%
	Subbituminous	47,508	80		40,949	67	16.0%	46,827	75	1.5%
West	Bituminous	6,888	126		6,742	116	2.2%	6,973	128	-1.2%
	Subbituminous	31,385	88		27,927	78	12.4%	29,400	78	6.8%
U.S. Total	Bituminous	83,661	95		71,696	76	16.7%	79,766	87	4.9%
	Subbituminous	87,470	83		73,939	68	18.3%	84,251	76	3.8%

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.