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Electricity Monthly Update

With Data for April 2017  |  Release Date: June 23, 2017  |  Next Release Date: July 25, 2017

Previous Issues

Highlights: April 2017

  • Mild spring weather lead to low daily peak demand levels at all electricity systems across the country.
  • Robust hydroelectric production in the Northwest leads to electricity prices as low as $3/MWh at Mid-C.
  • Electricity generation from natural gas decreased in all parts of the country, mainly due to the increase in the price of natural gas that occurred over the past year.

Key indicators




Natural gas consumption for power generation decreased during winter 2016-17

Natural gas use for power generation, sometimes called power burn, decreased in the United States this past winter (November 2016 – March 2017) compared to the previous winter (November 2015 – March 2016). Total natural gas consumption for power generation fell from 4,420 trillion British thermal units (TBtu) in the winter of 15/16 to 3,908 TBtu in the winter of 16/17, an 11.6% decrease.

This fall in demand can be traced mostly to higher spot natural prices and higher electric generation from coal, conventional hydroelectric, solar, and wind plants. Despite this winter-over-winter decline in natural gas use for power, power burn during winter 16/17 still exceeded the five-year winter average (from 2010-11 through 2014-15) of 3,606 TBtu by 8.4%.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report

Higher natural gas spot prices were a chief factor contributing to lower natural gas power burn this past winter. The 2016-17 winter average spot price of natural gas at the Henry Hub – the national benchmark for natural gas pricing – was $2.99 per million Btu (MMBtu), up $1.01/MMBtu, or 51%, from the average winter price for 2015-16. Spot natural gas price changes this winter reflected three major weather events.

  • A sustained period of cold weather from late November through mid-December boosted residential and commercial gas demand, resulting in spot natural gas prices rising to $3.75/MMBtu, making natural gas less competitive as a fuel for power generation compared with coal.
  • In contrast, February average temperatures were the warmest of any year since 1954, leading to less demand for heating. Natural gas prices dropped to less than $2.50/MMBtu.
  • March heating degree days (HDDs) were the same as February levels, and natural gas prices topped $3/MMBtu again at the end of the month.
Source: Intercontinental Exchange price through Ventyx Energy Velocity

The average wholesale price of electric at key trading hubs rose about $3-$8 per megawatthour (MWh) this winter, mostly as a result of higher average spot natural gas prices. Natural gas tends to be the “marginal fuel” for power generation in many of parts of the country. The price for all generating units selected to run is set by the highest offer price from a dispatched unit, especially in regional transmission organizations (RTOs). As a result, higher spot natural gas prices can translate into higher offer prices, which in turn can result in reduced output from natural gas generators and increased generation from other sources, such as coal.

Between winter 10/11 and winter 15/16, natural gas generation steadily increased, largely replacing coal-fired generation. During this time, natural gas generation rose by 48.4% (from 352,925 GWh to 523,781 GWh), while coal generation fell by 39% (from 746,402 GWh to 455,139 GWs). For the first time, natural gas generation during the winter exceeded coal generation in the United States. This trend, however, was reversed this past winter, when coal generation increased by 9.5% (to 498,254 GWh), while natural gas generation fell by 13.4% to 453,486 GWh. This past winter, coal once again was the leading generation source during the winter months.

Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report

Another factor that dampened natural gas consumption and generation during winter 16/17 was the increased use of renewables, particularly conventional hydroelectric power, in the western United States. In the Pacific Continuous region (California, Oregon, and Washington), natural gas generation fell from 52,296 gigawatthours (GWh) to 43,350 GWh, or by 17.1%, between winter 15/16 and winter 16/17. In the Pacific Contiguous region, renewables output was up markedly in winter 16/17 compared with the level in Winter 15/16:

  • Conventional hydroelectric power generation increased from 54,178 GWh to 68,567 GWh (26.6%).
  • Solar generation (including both utility-scale and distributed solar) rose from 7,808 GWh to 9,760 GWh (25%).
  • Wind generation also rose from 9,772 GWh to 10,381 GWh (6.2%).
Note: Pacific continuous regiona includes the states of California, Oregon and Washington.
Source: U.S. Energy Information Administration, Form EIA-923, Power Plant Operations Report


Principal Contributor:

Christopher Peterson
(Christopher.Peterson@eia.gov)

 

End Use: April 2017


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 9 states and the District of Columbia in April compared to last year. The largest declines were found in Utah (down 4%), Virginia (down almost 3%), and North Carolina (down almost 2%). Forty-one states increased compared to last year, led by Hawaii (up 14%), Oklahoma (up almost 13%), and Mississippi and New Mexico (each up nearly 11%).

Total average revenues per kilowatthour were up 2.7% to 10.10 cents in April compared to last year. All sectors were up on the month, with the Industrial sector leading at 3.1 %. The Commercial sector had the second-highest percent growth with 2.7%. The Residential sector followed with a growth of 2.2%. The Transportation sector showed a slight increase of 0.3% from last year. Total retail sales rose by 1%. The Residential sector gained the highest percent, up 3.0%, while the Commercial sector showed only a slight increase of 0.1%. The Industrial and Transportation sectors each declined slightly, -0.2% and -0.9%, respectively.

Retail sales



State retail sales volumes were down in 16 states in April compared to last year. California recorded the largest year-over-year decline, down 5.6%. Illinois had the next largest decline (down 3.8%), followed by Rhode Island and Maine, each dropping 3.3% from April 2016. Thirty-four states and the District of Columbia had retail sales volume increases in April, led by Oregon (up 7%), Delaware (up almost 6%), and Louisiana (up 5.5%).


Heating Degree Days (HDD) were down in 35 states and the District of Columbia compared to last April. Thirteen states had an increase in HDDs. Florida had no change from April 2016. The largest year-over-year decrease was found in the District of Columbia, down 54.6%. Every state east of the Mississippi river showed a drop of 30% or more in HDD, with the exceptions of Vermont (down 25.6%), Connecticut (down 24.5%), Rhode Island (down 23%), and Maine (down 15%). Of the 13 states with higher percentage increases in HDDs, the top 3 were all in the Pacific Northwest: Oregon (up 60%), Washington (up 50%), and Idaho (up 49%).

 

Resource Use: April 2017

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



map showing electricity regions

Net generation in the United States increased by only 0.3% compared to April 2016. The country, as a whole, experienced temperatures that were warmer than normal in April 2017, although temperatures the previous April were also warmer than normal. At the regional-level, all states east of the Mississippi River saw significantly above average temperatures, with many states in the MidAtlantic experiencing record heat in April 2017. Only states located in the northwest part of the country saw temperatures that were near or slightly below average during the month.

All regions of the country, except for the Northeast and MidAtlantic, saw an increase in electricity generation from coal compared to April 2016. Electricity generation from natural gas decreased in all parts of the country, with the Central region seeing the largest percent decrease (-30.1%) compared to the previous year. The overall increase in coal generation and subsequent decrease in natural gas generation mainly occurred due to the rise in natural gas prices that happened over the past year.

Net generation from nuclear was down 9.0%, as many nuclear plants were offline for spring maintenance compared to the previous year. Electricity generation from other renewable sources was up in all regions of the country, with Texas seeing the largest percent increase (39.7%) due to an increase in wind and solar plants that have come online since the previous year.

Fossil fuel consumption by region





map showing electricity regions

The chart above compares coal consumption in April 2016 and April 2017 by region and the second tab compares natural gas consumption by region over the same period. Changes in coal and natural gas consumption closely mirrored their respective changes in coal and natural gas generation.

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 April 2017, all regions of the country, except for the Northeast, saw an increase in the share of coal consumption at the expense of natural gas consumption.

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 increased from the previous month, going from $2.96/MMBtu in March 2017 to $3.19/MMBtu in April 2017. However, the natural gas price for New York City (Transco Zone 6 NY) decreased from the previous month, going from $3.57/MMBtu in March 2017 to $2.91/MMBtu in April 2017.

The New York Harbor residual oil price saw an increase from the previous month, going from $8.26/MMBtu in March 2017 to $8.44/MMBtu in April 2017. 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. The price of natural gas at Henry Hub was above the price of Central Appalachian coal on a $/MWh basis. This was mainly due to the rise in the price of natural gas at Henry Hub from the previous month. However, the price of natural gas at New York City on a $/MWh basis was below the price of Central Appalachian coal, due to the decrease in the price of natural gas at New York City since the previous month.

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: April 2017

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



Selected wholesale electricity pricing locations

Wholesale electricity prices ranged between $15-$46/MWh at selected hubs across the country except in Texas (ERCOT) and the Northwest (Mid-C) during the month of April. In Texas, prices hit $61/MWh on April 26 as hot weather enveloped the eastern and southern parts of the state. Houston hit 91 degrees Fahrenheit, matching the all-time record for the day, and the spring heat pushed up electricity demand and prices in ERCOT. In the Northwest, generally mild weather and robust hydroelectric production resulted in low prices in the range of $3-$23/MWh during the month. Water flow at The Dalles Dam, a run-of-the-river facility on the Columbia River east of Portland and good proxy for hydroelectric production in the Northwest, averaged 368,000 cubic feet per second in April, 12% higher than in March and 41% higher than April 2016.

Wholesale natural gas prices across the county ranged between $2.39-$3.90/MMBtu during April. Prices were considerably lower in the Northeast this month compared to March as temperatures warmed. A high price in New England (Algonquin) of $3.90/MMBtu was down from $8.25/MMBtu in March, a high price of $3.19/MMBtu in New York City (Transco Z6 NY) was down from $6.95/MMBtu in March and a high price of $3.14/MMBtu in the Mid-Atlantic (Tetco M-3) was down from $4.81/MMBtu in March.

Electricity system daily peak demand


Electric systems selected for daily peak demand

Electricity system daily peak demand levels in April were on the low end of the 12-month range in all systems across the country as mild spring weather reduced the need for heating and cooling demand. A new 12-month daily peak demand low of 65,146 MW was set in the Midwest (MISO) on April 8 and 12-month lows were nearly set at most of the other electricity systems during the month.

 

Electric Power Sector Coal Stocks: April 2017

 



In April, U.S. coal stockpiles increased to 166 million tons, up 1% from the previous month. This increase in total coal stockpiles is a normal occurance during the spring as the country builds up coal stockpiles to be used during the summer months when demand for electricity is greater.

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 decreased from 94 days of burn in March to 84 days of forward-looking days of burn in April. For subbituminous units largely located in the western United States, the average number of days of burn decreased from 97 days in March to 87 days in April.

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

  April 2017   April 2016   March 2017  
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 4,712 81   7,662 117 -38.5% 4,583 84 2.8%
  Subbituminous 145 226   171 184 -15.3% 145 251 0.0%
South Bituminous 32,491 82   37,153 88 -12.5% 31,894 93 1.9%
  Subbituminous 6,518 71   7,838 86 -16.8% 6,222 80 4.8%
Midwest Bituminous 15,362 89   18,387 95 -16.4% 15,271 97 0.6%
  Subbituminous 43,658 88   46,733 86 -6.6% 43,570 98 0.2%
West Bituminous 5,924 90   5,587 76 6.0% 5,937 100 -0.2%
  Subbituminous 32,205 89   41,393 103 -22.2% 31,500 100 2.2%
U.S. Total Bituminous 58,489 84   68,788 91 -15.0% 57,685 94 1.4%
  Subbituminous 82,525 87   96,135 93 -14.2% 81,438 97 1.3%

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.