U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Electricity Monthly Update
With Data for December 2013 | Release Date: Feb. 21, 2014 | Next Release Date: Mar. 21, 2014
Highlights: December 2013
- Wholesale electricity prices were very high in the Northeast. Prices peaked in New England to almost $206/MWh on December 16 and to just over $165/MWh in New York City on December 12.
- The majority of US states, 41 out of 50, had higher average revenues per kWh compared to last December.
- Net generation in the US increased 5.3 percent compared to the previous December because the U.S. experienced below normal temperatures in December 2013 and significantly above normal temperatures in December 2012.
|December 2013||% Change from December 2012|
|Total Net Generation
|Residential Retail Price
|Natural Gas Price, Henry Hub
|Natural Gas Consumption
New England Peak-to-Average Electric Demand Ratio Rising
Source: U.S. Energy Information Administration and Ventyx
Across the U.S., but most pronounced in New England, the ratio of annual peak-hour electric demand to average hourly demand has been rising over the last 20 years. In New England, the peak-to-average demand ratio has increased from 1.52 in 1993 to 1.78 in 2012 (see footnote for trend methodology). In other words, the highest peak-hour electric demand for the year in 1993 was 52% above the hourly average level while in 2012 peak-hour demand had risen to 78% above the hourly average level.
This translates into decreasing average utilization levels for generators in New England and other regions. Electric systems maintain sufficient capacity to meet expected peak loads plus a reserve margin. As the peak-to-average ratio rises, generators called on to meet peak-hour demand are running fewer hours and/or at lower output levels the rest of the year. Since energy payments are generator's primary source of revenue in Regional Transmission Organization (RTO) systems such as ISO New England, this trend in hourly demand is likely cutting into generator profits and increasing the importance of capacity market payments to generators.
Source: U.S. Energy Information Administration and Ventyx
A more nuanced way to look at hourly demand is the construction what is called a load duration curve. This is the graphical representation of hourly electric demand from highest to lowest over a certain time interval. In the chart above, hourly electric demand in New England for every hour of each year from 1993-2012 has been ordered from highest to lowest and indexed to the peak value for each year. It reveals two groups, one between the periods 1993-2000 and the second from 2001 to 2012.
We do not know the exact reasons for this change. But likely candidates include a rising share of climate control in electricity consumption (greater sensitivity to weather) lifting peak demand levels in the summer relative to average levels for the year, changes in consumption technologies and patterns (such as increased energy efficiency), and shifts to a more service-based economy (from an industrial base that uses energy more evenly throughout the year).
Source: U.S. Energy Information Administration and Ventyx
Source: U.S. Energy Information Administration and Ventyx
The fitted line in the peak-to-average demand ratio graphics is linear regression of the peak/demand ratio onto a trend variable using the regression equation Y = a + bT + e, where Y is the peak-to-average demand ratio, a is the estimated y-intercept, b is the estimated slope (trend), T is the trend variable, and e the error term.
Principal Contributor: Tim Shear
End Use: December 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
In December, the vast majority of US states, 41 out of 50, had average revenue per kWh figures higher than last December. Rhode Island (up 33.5%), Massachusetts (up 21.5%) and Idaho (up 13.8%) had the highest increases. Only nine states had average revenue per kilowatt figures lower than they recorded last December, led by West Virginia and Tennessee with decreases of more than five percent.
Retail Service by Customer Sector
Average Revenues/Sales (¢/kWh) Retail Sales (1000s MWh) End-use sector December 2013 Change from December 2012 December 2013 Change from December 2012 Year to Date Residential 11.72 0.9% 128,357 12.4% 1,391,090 Commercial 9.98 1.7% 108,849 4.5% 1,338,448 Industrial 6.62 1.5% 76,205 -2.8% 954,725 Transportation 10.17 -1.1% 665 7.5% 7,525 Total 9.88 2.5% 314,076 5.6% 3,691,789
Source: U.S. Energy Information Administration
Total average revenues per kilowatthour averaged 9.88 cents in December, up slightly from November's 9.83 cent average and an increase of 2.5 percent from last December. The commercial sector had the largest increase from last year, 1.7 percent, followed by the industrial (1.5%) and residential (0.9%) sectors. The transportation sector, a small component of total, was down 1.1% from last December.
Total retail sales volumes increased 5.6 percent from last December to 314,076 GWh. This is largely due to the much colder weather most of the country experienced this December. The residential sector, most sensitive to low temperatures, had a 12.4 percent increase in retail sales volumes from last December while commercial sector volumes rose 4.5 percent. The industrial sector, much more immune to changes in temperature, was down 2.8 percent from last December.
Electric industry retail sales volumes rose in all but four states in December relative to one year ago. Texas, Arkansas, South Dakota and Oregon all had retail sales volume increases higher than 10 percent from last year. Only Kentucky, Alaska, Massachusetts, and Hawaii had lower retail sales volumes this December compared to last December.
Kentucky's sales volumes continue to be significantly lower than previous years' levels due to the closure of United States Enrichment Corporation's Paducah Gaseous Diffusion Plant in Paducah, KY. This facility was a large consumer of electric power and its absence makes a noticeable difference in Kentucky's retail sales volumes.
This December saw the arrival of cold winter weather across much of the country, especially when compared to a mild December 2012. Only Florida, California, and Alaska had lower heating degree day (HDD) totals this December than last year. The colder weather relative to last year was most pronounced in the South and Midwest as Texas, Louisiana, Illinois, Mississippi, Wisconsin, Arkansas, Oklahoma, Missouri, Indiana, and Michigan all had increases of more than 30% HDDs compared to last December.
Relative to long-term normal levels (see the second tab), most states in the Southeast and Mid-Atlantic regions were actually warmer than normal, though cooler than in 2012.
Resource Use: December 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 in December 2013 compared to the previous year. This year-over-year increase in electricity generation occurred because the U.S. experienced below normal temperatures in December 2013 and significantly above normal temperatures the previous December. This lead to an increase in residential heating compared to last year which caused increased demand for electricity generation during December 2013. The only region that experienced a decrease in electricity generation in December 2013 was Florida, where the overall average temperature for the month was close to the record high temperature for December. This caused Florida to have a 1.6 percent decrease in electricity generation compared to last December.
In December 2013, electricity generation from coal increased in all regions of the country except for the West. The change in natural gas generation was much more varied, with the Mid-Atlantic, Central, West, and Texas experiencing increases in natural gas generation. This increase in generation was likely a result of the below normal temperatures experienced in December 2013 compared to the warm December experienced the previous year. The Northeast, Southeast, and Florida all experienced decreases in natural gas generation compared to last December.
Electricity generation from nuclear plants increased in almost all parts of the country, except for in the Northeast and West where nuclear generation was down slightly from the previous year. Other fossil generators, mainly used for peaking purposes during times of increased electricity demand, increased electricity generation in all regions of the country, except for Florida, compared to the previous year.
Fossil Fuel Consumption by Region
The chart above shows that the change in coal consumption mirrored the change in electricity generation from coal.
The second tab compares natural gas consumption in December 2012 and December 2013 by region. This consumption pattern is consistent with changes in natural gas generation, with the Mid-Atlantic, Central, West, and Texas experiencing increases in natural gas consumption and the Northeast, Southeast, and Florida experiencing 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 the Northeast, Southeast, Florida, and Texas at the expense of natural gas. The West, Central, and Mid-Atlantic regions all saw natural gas increase its share of total fossil fuel consumption at the expense of coal. Also of note, other fossil fuels in the Northeast cut into natural gas's share of total fossil fuels.
The fourth tab presents the change in coal and natural gas consumption on an energy content basis between December 2012 and December 2013 by region. Once again, the change in total coal and natural gas consumption was very similar to the change seen in total coal and natural gas net generation in each region.
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. The price of natural gas at Henry Hub increased significantly from the previous month, going from $3.75 / MMBtu in November 2013 to $4.38 / MMBtu in December 2013. The natural gas price for New York City (Transco Zone 6 NY) also experienced a significant increase from the previous month, going from $3.91 / MMBtu in November 2013 to $6.12 / MMBtu in December 2013. Increases of this magnitude in New York City's natural gas price are often observed during this time of year when there is an increased demand for natural gas used for heating in an area of the country where the natural gas pipeline infrastructure is subject to significant congestion. The price of Central Appalachian decreased slightly from the previous month, going from $2.73 / MMBtu in November 2013 to $2.72 / MMBtu in December 2013.
For the fifth consecutive month, the average price of residual oil priced at New York Harbor increased from the previous month, rising from $19.76 / MMBtu in November 2013 to $20.02 / MMBtu in December 2013.
A fuel price comparison based on equivalent energy content ($ / 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. Due to the significant increase in the price for natural gas, the spread between the Henry Hub and New York City natural gas prices climbed well above the price of Central Appalachian coal on a $ / MWh basis in December 2013.
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: December 2013
The United States has many regional wholesale electricity markets. Below we look at monthly and annual ranges of on-peak, daily wholesale prices at selected pricing locations and daily peak demand for selected electricity systems in the Nation. The range of daily prices and demand data is shown for the report month and for the year ending with the report month.
Prices and demand are shown for six Regional Transmission Operator (RTO) markets: ISO New England (ISO-NE), New York ISO (NYISO), PJM Interconnection (PJM), Midwest ISO (MISO), Electric Reliability Council of Texas (ERCOT), and two locations in the California ISO (CAISO). Also shown are wholesale prices at trading hubs in Louisiana (into Entergy), Southwest (Palo Verde) and Northwest (Mid-Columbia). In addition to the RTO systems, peak demand is also shown for the Southern Company, Progress Florida, Tucson Electric, and the Bonneville Power Authority (BPA). Refer to the map tabs for the locations of the electricity and natural gas pricing hubs and the electric systems for which peak demand ranges are shown.
In the second tab immediately below, we show monthly and annual ranges of on-peak, daily wholesale natural gas prices at selected pricing locations in the United States. The range of daily natural gas prices is shown for the same month and year as the electricity price range chart. Wholesale electricity prices are closely tied to wholesale natural gas prices in all but the center of the country. Therefore, one can often explain current wholesale electricity prices by looking at what is happening with natural gas prices.
Daily wholesale electricity prices at ten locations were significantly higher in December than they were in November. This was due to a combination of higher demand and higher natural gas prices across most of the country as a result of the onset of colder winter weather.
Wholesale electricity prices were highest in the Northeast. Prices peaked in New England to almost $206/MWh on December 16 and to just over $165/MWh in New York City on December 12. Daily peak demand levels in both ISONE and NYISO were much higher in December than in November.
The primary factor was higher natural gas prices in the Northeast, due to the use of natural gas-fired peaking units and the sensitivity to natural gas price movements in this region. In New England, Algonquin Citygate prices reached $32.25/MMBtu on December 16 and averaged $13.37/MMBtu for the month, more than triple the $4.22/MMBtu average price at Henry Hub in Louisiana. In New York City, Transco Zone 6-NY natural gas prices peaked at $16.13/MMBtu on December 12 and averaged $5.52/MMBtu for the month. And in the Mid-Atlantic, prices peaked just short of $12/MMBtu at Tetco M-3. The rest of country set yearly maximum values for natural gas prices in December, though price levels ranging from $4.45/MMBtu at Houston Ship Channel to $8/MMBtu at Southern California (SoCal) Border fell well short of peak prices found in the Northeast.
In the Midwest, electricity prices approached $50/MMBtu as brutally cold weather drove MISO load levels to 91,715 MW on December 30, just 6,811 MW short of the all-time peak. Low temperatures in Minneapolis reached -11 degrees Fahrenheit on December 29 and -13 degrees Fahrenheit on December 30, both records for those days.
In the Northwest, electric prices reached $93/MWh on December 9 as an extended bout of cold weather drove low temperatures nearly 20 degrees below normal levels and local Sumas natural gas prices reached $11/MMBtu, well above the $5.03/MMBtu average for the month. Daily peak electric demand for the Bonneville Power Administration exceeded 10,000 megawatts on three days between December 5-9, reaching 92% of BPA's all-time maximum on the 9th.
Electricity System Daily Peak Demand
Prices set a yearly maximum value in Louisiana on December 9 of $42.50/MMBtu during middle of a long stretch of below normal temperatures in the region, though this was the lowest peak of any region for the month.
Electric Power Sector Coal Stocks: December 2013
In December 2013, total coal stocks decreased 5.0 percent from the previous month. This follows the normal seasonal pattern for this time of year as the country begins to consume more coal for electricity generation during the winter months. Compared to last December, coal stocks decreased 20.1 percent. This occurred because coal stocks in December 2012 were at an extremely high level.
Days of Burn
The average number of days of burn held at electric power plants is a forward looking estimate of coal supply given a power plant's current stockpile and past consumption patterns. The total bituminous supply decreased from 71 days the previous month to 63 days in December 2013, while the total subbituminous supply decreased from 56 days in November 2013 to 48 days in December 2013.
Coal Stocks and Average Number of Days of Burn for Non-Lignite Coal by Region (Electric Power Sector)
|December 2013||December 2012||November 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.