Electricity
Electricity Monthly Update
With Data for July 2012 | Release Date: September 24, 2012 | Next Release Date: October 26, 2012 |
Re-Release Date: September 27, 2012 (correction)
Previous Issues of Electricity Monthly Update
Highlights: July 2012
- July 2012 was the hottest July on record for the continental United States. However, population-weighted cooling degree days actually decreased by 0.7 percent from July 2011, as it was hotter in places with relatively less dense populations.
- The average cost of electricity fell in all sectors compared to July 2011, with total average revenues decreasing 2.1 percent from the previous year.
- Coal stocks decreased for the third month in a row, after increasing for eight straight months from August 2011 to April 2012.
Key Indicators
| July 2012 | % Change from July 2011 | |
|---|---|---|
| Total Net Generation (Thousand MWh) |
416,152 | -0.8% |
| Residential Retail Price (cents/kWh) |
12.04 | -1.0% |
| Retail Sales (Thousand MWh) |
369,957 | 0.4% |
| Cooling Degree-Days | 408 | -0.7% |
| Natural Gas Price, Henry Hub ($/MMBtu) |
3.05 | -32.7% |
| Coal Stocks (Thousand Tons) |
184,586 | 24.7% |
| Coal Consumption (Thousand Tons) |
86,575 | -8.1% |
| Natural Gas Consumption (Mcf) |
1,117,710 | 15.8% |
| Nuclear Outages (MW) |
8,267 | 99.5% |
States with EERS consume less electricity per capita than those without
Over the last decade, 29 states have created energy efficiency resource standards (EERS) or efficiency goals (see map below). These programs vary greatly from state to state; most of them are mandatory goals while some are voluntary, some have small savings goals while others are more ambitious, some have relatively near-term goals while others are more long-term, and each incentivizes or mandates savings in various ways.
Many of these programs have been in effect for several years now, and some states have emerged as more intensive users of electric energy than others, especially those without any EERS. One way to compare states' energy consumption at a glance is to look at the second map above (which is normally found in the End Use section), sshowing electricity retail sales per capita by state. All else being equal, a state with a high level of per capita retail sales (which we use in place of consumption) uses electricity less efficiently than a state with a low level of per capita sales. There are also other factors that will affect the level of retail sales per capita, including weather, regional fuel usage, industrial output, and population density.
This population-normalized comparison is useful in comparing the effectiveness of state energy efficiency policies. It should be noted that while residential sales will depend on population, electricity sales to commercial and industrial customers are less influenced by population. This would tend to raise per capita sales in states with large commercial and industrial activity relative to a state's population, as compared to other states. However, since efficiency programs apply across all customer segments, we use total sales. If one looks at residential sales alone, the results do not change much. Some of the less populous states like Wyoming drop down the list of sales per capita, while more populous ones like Georgia rise in the ranks. With either approach, states with EERS are more efficient in terms of sales per capita, particularly those with a more robust EERS, like New York.
Click on chart to enlarge and show specific states.
For July, the population-weighted average per capita sales in the top 20 percent of per capita electricity sales (least efficient) were just above 1,800 kWh/capita, while those of the bottom 20 percent (most efficient) were about 680 kWh/capita. It is important to note that the 10 states in the top 20 percent are regionally diverse, which makes it less likely that regional factors are influencing the numbers significantly. Of the 9 states and the District of Columbia that make up the top 20 percent, only one of them, Arkansas, has a voluntary EERS. Conversely, of the 20 states in the bottom 40 percent, 16 have EERS, 12 of which are mandatory.
There are a few exceptions to the trend, notably Arkansas, Indiana, and Iowa, which have EERS but their sales per capita are high. These State's EERS have relatively low efficiency goals. These programs are also relatively new, all having been adopted in 2009 or later.
On the other side of the spectrum there are some states with no EERS that have low per capita sales like Alaska, which has a very low annual electric demand relative to other states. Another notable exception is New Jersey, which has the second highest installed capacity of solar power on a MW basis behind California due to the State's robust renewable energy goals and incentives to consumers for installing solar panels on their homes and businesses. It may be that not only are the many consumers of distributed solar power in New Jersey buying less power from their utilities, they also may be more aware of their energy usage and have adopted energy efficient practices as well.
We also looked at trends over time. Comparing 2002 and 2011 retail sales per capita data, states with no EERS programs had a per capita consumption increase of over 9 percent, while the states with mandatory EERS programs had an increase of just above 5 percent over the same period, a marked improvement. States with voluntary EERS had a per capita increase of almost 11 percent, slightly more even than the states with no EERS. This could be due to the fact that of the seven states with voluntary EERSs, only Vermont's and Texas's were instituted before 2010, so these states have only had a few years to begin saving energy.
Principal Contributor: Eric Schneiter (eric.schneiter@eia.gov)
End Use: July 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
Compared to July 2011, the average cost of electricity fell in many States located in the Northeast. The exceptions were Rhode Island and Vermont, where the average cost of electricity increased by 2.1 percent and 3.9 percent, respectively. Revenues per kilowatthour also decreased in every Gulf Coast State, except for Alabama, which observed a slight increase of 0.6 percent when compared to July 2011. Like last month, the largest year-over-year increases in average cost occurred in Wyoming and Utah, where revenues per kilowatthour increased 13.0 percent and 11.7 percent, respectively. The largest decline occurred in Louisiana, where average cost decreased 15.4 percent from July 2011.
The average cost of electricity fell in all sectors compared to July 2011, with total average revenues decreasing 2.1 percent from the previous year. The volume of retail sales of electricity increased slightly in the commercial and industrial sectors, while remaining relatively flat in the residential sector and only decreasing by 0.5 percent in the transportation sector. One notable year-over-year decrease in retail sales and average revenues occurred in Texas, where the State experienced its hottest July on record in 2011, and then slightly above normal temperatures in July 2012.
Retail Sales
As observed by the map below of cooling degree days (CDDs) deviation from normal, July 2012 was very warm for most of the country. The exceptions occurred in Nevada, Arizona, Alaska and Hawaii. Compared to last July, many States in the lower half of the Nation experienced a decrease in cooling degree days, whereas many States in the top half of the country experienced an increase in cooling degree days. The most notable States that were exceptions to this trend were located in the Mid-Atlantic and New England.
Resource Use: July 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
Throughout the continental United States as a whole, net generation decreased 0.8 percent in July 2012 compared to July 2011. This followed the 0.7 percent decline in population-weighted cooling degree days observed in the continental U.S. over the same period. As observed over many of the prior months, natural gas continued to increase its share as a percentage of total generation in July 2012, cutting into the monthly electricity generation share produced at coal-fired power plants a year earlier. Thus, gas-fired, combined cycle units continue to provide more electricity generation at the expense of fossil steam generators (which are primarily coal-fired). This trend was most pronounced in the west, southeast, and central regions.
Fossil Fuel Consumption by Region
In tandem with net generation, the chart above shows that coal consumption decreased in all parts of the continental U.S. The Southeastern, Central, and Mid-Atlantic regions continue to see the most significant drop in coal consumption compared to last year.
The second tab compares natural gas consumption in July 2011 and July 2012 by region. Consistent with the increase in natural gas-fired generation, natural gas consumption increased in all regions except for Texas. This decrease in natural gas-fired generation in Texas occurred because total generation was down in 2012 as the State experienced its hottest July on record in 2011.
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. Similar to trends in physical consumption, natural gas displaced coal as a percent of fossil fuel in all regions of the Nation.
The fourth tab presents the change in the relative share of fossil fuel (coal and natural gas) consumption on an energy content basis from July 2011 and July 2012 by region. Total fossil fuel use increased in the west region due to warmer weather and reduced hydro generation, while the rest of the country saw total fossil fuel use stay relatively the same or slightly decrease.
Fossil Fuel Prices
To gain some insight into the changing pattern of consumption of fossil fuels between July 2011 and July 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. After reaching a low of $2.03 / MMBtu in April 2012, the price of Henry Hub natural gas has increased by over 50 percent to $3.05 / MMBtu in July 2012. Over the same time period, Central Appalachian coal decreased by 6.7 percent.
After dropping for three months in a row, the average price of residual oil increased 4.5 percent from the previous month to $17.75 / MMBtu in July 2012. Regardless, it remains almost always priced out of the market in the continental United States.
A fuel price comparison based on equivalent energy content ($/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. This comparison shows that the average July 2012 price in $/MWh for Central Appalachian coal is still higher than the price of natural gas at Henry Hub for the twelfth straight month. However, because of the increase in the price of natural gas, the gap between the two closed even further in July 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: July 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 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
Wholesale electricity prices remained below $46/MWh for most of the country, while hubs in the Midwest, Mid-Atlantic and New England stayed mostly between $40/MWh and $60/MWh. Notable exceptions to this were on July 17th and 18th at PJM, NYISO, MISO, where prices spiked well over $60 to a high of nearly $146/MWh for NYISO on the 18th. NYISE topped $81/MWh again on July 26, and ERCOT had a spike late in the month which raised prices there to $95/MWh on the 31st.
Natural gas prices remained at relatively low levels across much of the country as abundant supply kept prices around $3/MMBtu. The notable exception was at the Algonquin Hub in New England, where prices fluctuated all month and spiked to $6.41/MMBtu on July 17. Prices at all hubs averaged just over $3/MMBtu for the month of July. Prices at all hubs except Algonquin rose fairly steadily over the course of July, from an average of $2.78/MWh on July 1st to $3.13/MWh on July 31st.
Electricity System Daily Peak Demand
The monthly range of daily peak-hour demand as a percentage of all-time peak demand for July 2012 compared to the annual range varied a lot from region to region, though July saw some of the heaviest demand loads for the year so far at a number of hubs. ISONE, NYISO, PJM, MISO, Southern Company, ERCOT, and Tucson Electric all posted monthly-high peak loads above 90 percent of their systems' all-time peak demand during the month of July. Four of these monthly high demand loads (at ISONE, NYISO, PJM, and MISO) were also the highest levels all year. MISO (Midwest) led the group by getting to almost 100 MW of their all-time peak demand record on July 23rd.
Electric Power Sector Coal Stocks: July 2012
In July 2012, total coal stocks decreased 7.0 percent from the previous month as the continental United States consumes more coal for electricity generation during the hot, summer months. However, total coal stocks remained at relatively high levels in July 2012, due to the relatively cheap price of natural gas observed over the previous month.
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 July 2012, total bituminous supply continued to show a slight uptick from the previous month, increasing to 82 days of burn. Total subbituminous supply remained unchanged at 71 days of burn. However, because coal consumption patterns are significantly different than past years, the actual days of burn held at electric power plants is likely higher than this metric, which is based on past consumption patterns.
Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)
| July 2012 | July 2011 | June 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 | 7,454 | 61 | 6,200 | 45 | 20.2% | 9,501 | 70 | -21.5% | |
| Subbituminous | 485 | 31 | 517 | 24 | -6.2% | 533 | 34 | -9.1% | ||
| South | Bituminous | 46,847 | 87 | 35,930 | 57 | 30.4% | 51,718 | 84 | -9.4% | |
| Subbituminous | 7,549 | 70 | 4,115 | 36 | 83.4% | 8,118 | 71 | -7.0% | ||
| Midwest | Bituminous | 17,890 | 73 | 13,065 | 50 | 36.9% | 19,404 | 72 | -7.8% | |
| Subbituminous | 46,014 | 68 | 38,060 | 54 | 20.9% | 48,842 | 67 | -5.8% | ||
| West | Bituminous | 7,410 | 126 | 7,502 | 122 | -1.2% | 7,354 | 118 | 0.8% | |
| Subbituminous | 33,987 | 77 | 27,079 | 61 | 25.5% | 35,238 | 77 | -3.6% | ||
| U.S. Total | Bituminous | 79,601 | 83 | 62,698 | 58 | 27.0% | 87,977 | 82 | -9.5% | |
| Subbituminous | 88,035 | 71 | 69,770 | 54 | 26.2% | 92,732 | 71 | -5.1% | ||
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.