End Use: January 2016

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

Average revenue per kilowatthour figures decreased in 27 states and the District of Columbia and increased in 23 states in January compared to last year. Hawaii had the largest decrease for the thirteenth month in a row, down 20% from last year as lower world oil prices continue to benefit Hawaii's largely petroleum-fueled bulk power system. The next largest year-over-year declines were found in New York, down 13%, and Nevada, down 11% from last year. The largest year-over-year increase occurred in West Virginia, up 16%, followed by Washington, up 11%, and Delaware, up 9%.

Average revenues per kilowatthour and retail sales volumes were both lower in total and across all sectors in January when compared to last year. Average revenues per kilowatthour were 9.96 cents in January, down 2.2% from last year. Retail sales volumes totaled 318,075 gigawatthours (GWh), down 2.5% from last year. The Residential sector, also the most sensitive to weather, had the largest sales volume declines (-4.9%) as the warmest winter on record subdued electricity demand to some extent.

Retail sales

State retail sales volumes were mostly down in January compared to last year. 42 states and the District of Columbia, including every state east of the Mississippi River, had lower retail sales volumes, led by Delaware which was down over 15%. New Jersey (-8%), Tennessee (-7%), Indiana, and Maryland (both down 6%), had the next largest year-over-year declines. The eight states with retail sales volume increases were scattered throughout the West (and Hawaii). Hawaii had the largest increase, up nearly 4%, with Arizona close behind, up over 3%. Hawaii's increased volumes can be traced to a sustained pattern of warm, dry weather. High temperatures in Honolulu were at or above average 30 of 31 days during the month, with virtually no rainfall which is well below normal precipitation amounts. In Hilo on the Big Island, high temperatures in the high-80's set records on several days during the month.

Heating Degree Days (HDD) measure the daily variation in average temperature from a 65 degree Fahrenheit baseline, chosen as a proxy for minimum heating or cooling energy demand. HDDs fell in 22 states across the Northeast, Great Lakes and lower Midcontinent regions this January compared to last year, indicating warmer weather. The largest HDD decreases were found in the Northeast, with New Hampshire, Maine, Vermont, and New York the top four states with HDD declines between 15%-17%. HDDs increased in 28 states across the Southeast and West and the District of Columbia, indicating colder weather in these regions compared to last year. California had the largest HDD increase, up 33%, followed by Florida, up 31%, and Nevada, up 23%.

 

Resource Use: January 2016

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 decreased 3% in January 2016 compared to the previous year. At the region-level, all regions of the country saw decreases in electricity generation compared to the previous January. The largest percent decrease from the previous January occurred in Texas (-6.8%), where temperatures returned to near average in January 2016 after the state experienced below average temperatures in January 2015. The only areas that experienced a minimal decrease in electricity generation were the Southeast region (-0.4%) and Florida (-0.3%), where each experienced temperatures that were similar to January 2015.

In January 2016, electricity generation from coal continued to show a year-over-year decrease in all regions. Natural gas generation increased in all regions of the country, except for in Texas, where electricity generation decreased due to the previously mentioned decline in residential heating due to weather conditions. Nuclear generation was down 2.3% compared to January 2015, with the largest percent decrease occurring in the Southeast region (-6.1%), where unit one at the Sequoyah nuclear plant was offline for maintenance in January 2016, whereas in the previous January, the plant operated at full capacity.

Fossil fuel consumption by region

The chart above compares coal consumption in January 2015 and January 2016 by region and shows that, like electricity generation from coal, coal consumption decreased in all regions of the country.

The second tab compares natural gas consumption by region and shows that increases in natural gas consumption from the previous January mirrored the increases in electricity generation from natural gas over the same period, including Texas, where natural gas consumption decreased compared to the prior January.

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. In January 2016, the share of natural gas consumption increased in all regions of the country at the expense of coal consumption compared to the previous year. In the Northeast, natural gas also increased its share at the expense of other fossil fuels, which saw a larger than usual share of fuel consumption during the previous January.

The fourth tab presents the change in coal and natural gas consumption on an energy content basis by region. The changes in total coal and natural gas consumption were similar to the changes 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 average price of natural gas at Henry Hub had its first month-over-month increase since July 2015, going from $1.95/MMBtu in December 2015 to $2.35/MMBtu in January 2016. The natural gas price for New York City (Transco Zone 6 NY) saw a significant increase from the previous month, going from $1.69/MMBtu in December 2015 to $3.76/MMBtu in January 2016. This increase in New York City's natural gas price is 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.

For the third consecutive month, the New York Harbor residual oil price decreased from the previous month, going from $5.91/MMBtu in December 2015 to $5.14/MMBtu in January 2016. Regardless, oil used as a fuel for electricity generation is almost always priced out of the market.

A fuel price comparison based on equivalent energy content ($/MMBtu) does not reflect differences in energy conversion efficiency (heat rate) among different types of generators. Gas-fired combined-cycle units tend to be more efficient than coal-fired steam units. The second tab shows coal and natural gas prices on an equivalent energy content and efficiency basis. For the thirteenth consecutive month, the price of natural gas at Henry Hub was below the price of Central Appalachian coal on a $/MWh basis. However, the spread between the two prices decreased significantly, mainly due to the large increase in the price of natural gas at Henry Hub. The price of natural gas at New York City on a $/MWh basis was above the price of Central Appalachian coal for the first time since March 2015, due to the large increase in the price of natural gas at 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: January 2016

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 and natural gas prices were much lower this January than in years' past, particularly in the Northeast. A combination of warmer-than-normal temperatures across the Northeast, additional pipeline infrastructure, and the generally well-supplied and low-priced natural gas environment led to regional prices just a fraction of what happened over the last several years. In the electricity market, peak prices for the month reached only $66/MWh in New England (ISONE), down from $110/MWh last year and $438/MWh two years ago. Peak prices in New York City (NYISO) reached only $71/MWh this year, down from $124/MWh last year and $518/MWh two years ago. In the Mid-Atlantic (PJM), peak prices reached only $46/MWh this year, down from $82/MWh and $683/MWh two years ago. Across the rest of the country, peak prices remained below $37/MWh at all other selected trading points.

The low wholesale natural gas prices this January were even more pronounced than the fall in wholesale electricity prices. Peak prices for the month reached only $7.85/MMBtu in New England (Algonquin), down from $14.37/MMBtu last year and $78/MMBtu two years ago. Peak prices in New York City (Transco Z6 NY) reached only $6.66/MMBtu this year, down from $18.11/MMBtu last year and $121/MMBtu two years ago. In the Mid-Atlantic (Tetco M-3), peak prices reached only $4.56/MMBtu this year, down from $16.70/MMBtu and $92/MMBtu two years ago. Peak prices remained below $2.85/MMBtu at the other seven selected trading points around the country, very low levels for any month much less a peak winter month which often records the highest prices and demand for the year.

Electricity system daily peak demand

Electricity system daily peak demand this January was lower than last year in all regions except California (CAISO), Progress Florida, and the Bonneville Power Administration (BPA) footprint. California loads peaked during the first week of the month (though loads were low compared to other times of the year), as cool weather and heavy precipitation blanketed the state. Progress Florida's 10,764 megawatt (MW) peak demand was 18% higher than its peak last January, though winter loads are considerably lower in this region than those occurring during summer months. In BPA, daily peak demand of 9,365 MW was just 200 MW lower than its 12-month peak.

 

Electric Power Sector Coal Stocks: January 2016

 

In January, U.S. coal stockpiles decreased to 189 million tons, down 4% from the previous month. This decrease in December-to-January coal stockpiles follows the normal seasonal pattern where stockpiles decrease during the winter months. However, overall U.S. coal stockpile are still at very high levels due to the loss in market share to natural gas in all regions of the country.

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. For bituminous units largely located in the eastern United States, the average number of days of burn increased from 91 days of burn in December to 94 days of forward-looking days of burn in January. For subbituminous units largely located in the western United States, the average number of days of burn increased, going from 95 days in December to 101 days in January. The 94 days of burn for bituminous units is the second highest level of days reached since this metric was calculated beginning in January 2010, and the 101 days of burn for subbituminous units is the highest level of days reached over this same period.

Coal stocks and average number of days of burn for non-lignite coal by region (electric power sector)

		January 2016			January 2015			December 2015
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	7,963	100		7,049	91	13.0%	8,431	92	-5.5%
	Subbituminous	652	220		785	205	-17.0%	675	174	-3.4%
South	Bituminous	35,808	97		33,101	85	8.2%	38,762	95	-7.6%
	Subbituminous	7,792	98		6,184	82	26.0%	8,145	97	-4.3%
Midwest	Bituminous	17,447	91		14,415	74	21.0%	18,625	88	-6.3%
	Subbituminous	46,652	87		33,409	58	39.6%	48,526	82	-3.9%
West	Bituminous	4,852	78		4,515	69	7.5%	5,331	77	-9.0%
	Subbituminous	40,971	121		28,826	82	42.1%	40,914	116	0.1%
U.S. Total	Bituminous	66,071	94		59,079	81	11.8%	71,149	91	-7.1%
	Subbituminous	96,066	101		69,204	69	38.8%	98,260	95	-2.2%

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 are proprietary and non-public.

Key Indicators

The Key Indicators in the 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, 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.
Degree-Days:  Reflects the total population-weighted United States 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.  The data are 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 (IPPs), including IPP plants that operate as CHPs). 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 units 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 a primary fuel of lignite or 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.

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.