Between 2010 and the first quarter of 2019, U.S. power companies announced the retirement of more than 546 coal-fired power units, totaling about 102 gigawatts (GW) of generating capacity. Plant owners intend to retire another 17 GW of coal-fired capacity by 2025, according to the U.S. Energy Information Administration’s (EIA) Preliminary Monthly Electric Generator Inventory. After a coal unit retires, the power plant site goes through a complex, multi-year process that includes decommissioning, remediation, and redevelopment.
Coal-fired power plants in the United States remain under significant economic pressure. Many plant owners have retired their coal-fired units because of relatively flat electricity demand growth and increased competition from natural gas and renewables. In 2018, plant owners retired more than 13 GW of coal-fired generation capacity, which is the second-highest annual total for U.S. coal retirements in EIA’s dataset; the highest total for coal retirements, at 15 GW, occurred in 2015.
In 2018, 89 utilities—or nearly half of all major U.S. electric utilities—tried to change electricity rates by filing rate cases with state regulatory commissions; this number was the largest number since 1983. U.S. public electric utility companies must obtain permission from their regulators before changing the rates they charge customers. Of the 89 utilities filing rate cases in 2018, 10 proposed to decrease rates, 1 negotiated a rate freeze until 2020, and the other 78 utilities proposed rate increases.
Regulated electric utilities can request rate changes to help recover expenses for building, operating, and maintaining their electric generators, transmission and distribution equipment, and other buildings and equipment. In addition, utilities have the right to earn a return on their investments.
The number of electric utility rate cases typically reflects changes in the costs of generating and delivering electricity. In 2018, increases in spending for electricity transmission and delivery, rather than for electric generation, drove most of the approved rate increases.
In its July 2019 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts Henry Hub natural gas spot prices for June, July, and August this year will average $2.37 per million British thermal units (MMBtu). If realized, this price would be the lowest summer average Henry Hub natural gas price since 1998. EIA expects Henry Hub natural gas prices will be 55 cents/MMBtu, about 19%, lower than last summer’s average.
In the July STEO, EIA revised its forecast for 2019 Henry Hub natural gas prices down from the June STEO following three consecutive months of price declines. Prices in June averaged $2.40/MMBtu and have declined by 19% since March.
After a 2.7% increase in U.S. energy-related carbon dioxide (CO2) emissions in 2018, EIA’s July Short-Term Energy Outlook (STEO) forecasts a 2.2% decrease in CO2 emissions for 2019. Nearly all of the forecast decrease is due to fewer emissions from coal consumption. Forecast natural gas CO2 emissions increase and petroleum CO2 emissions remain virtually unchanged.
Based on data in EIA’s Monthly Energy Review, energy-related CO2 emissions in the first three months of 2019 were largely similar to those in the first three months of 2018. In the first quarter of 2019, EIA estimates that U.S. energy-related emissions totaled 1,367 million metric tons (MMmt), which is nearly equal to those in the first quarter of 2018.
Utility-scale battery storage units (units of one megawatt (MW) or greater power capacity) are a newer electric power resource, and their use has been growing in recent years. Operating utility-scale battery storage power capacity has more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW). Assuming currently planned additions are completed and no current operating capacity is retired, utility-scale battery storage power capacity could exceed 2,500 MW by 2023.
EIA's Annual Electric Generator Report (Form EIA-860) collects data on the status of existing utility-scale battery storage units in the United States, along with proposed utility-scale battery storage projects scheduled for initial commercial operation within the next five years. The monthly version of this survey, the Preliminary Monthly Electric Generator Inventory (Form EIA-860M), collects the updated status of any projects scheduled to come online within the next 12 months.
In mid-April, Colorado’s governor signed a law changing the way the state regulates its oil and natural gas industry. Senate Bill 181, also known as Protect Public Welfare Oil and Gas Operations, amends the Oil and Gas Conservation Act and gives counties and municipalities increased regulatory authority over oil and natural gas development in their jurisdictions.
In April 2019, U.S. monthly electricity generation from renewable sources exceeded coal-fired generation for the first time based on data in EIA’s Electric Power Monthly. Renewable sources provided 23% of total electricity generation to coal’s 20%. This outcome reflects both seasonal factors as well as long-term increases in renewable generation and decreases in coal generation. EIA includes utility-scale hydropower, wind, solar, geothermal, and biomass in its definition of renewable electricity generation.
In the United States, overall electricity consumption is often lowest in the spring and fall months because temperatures are more moderate and electricity demand for heating and air conditioning is relatively low. Consequently, electricity generation from fuels such as natural gas, coal, and nuclear is often at its lowest point during these months as some generators undergo maintenance.
As of the end of 2018, 29 states and the District of Columbia had renewable portfolio standards (RPS), or polices that require electricity suppliers to source a certain portion of their electricity from designated renewable resources or eligible technologies. Four states—New Mexico, Washington, Nevada, and Maryland—and the District of Columbia have updated their RPS since the start of 2019.
States with legally binding RPS collectively accounted for 63% of electricity retail sales in the United States in 2018. In addition to the 29 states with binding RPS policies, 8 states have nonbinding renewable portfolio goals.
Wells drilled horizontally into tight oil and shale gas formations continue to account for an increasing share of crude oil and natural gas production in the United States. In 2004, horizontal wells accounted for about 15% of U.S. crude oil production in tight oil formations. By the end of 2018, that percentage had increased to 96%. Similarly, horizontal wells made up about 14% of U.S. natural gas production in shale formations in 2004 and increased to 97% in 2018.
Although horizontal wells have been the dominant source of production from U.S. shale gas and tight oil plays since 2008 and 2010, respectively, the number of horizontal wells did not surpass the number of vertical wells drilled in these plays until 2017. About 88,000 vertical wells in tight oil and shale gas plays in the United States still produced crude oil or natural gas at the end of 2018, but the volume produced by these wells was minor compared with the volume produced by horizontal wells. Many of these remaining vertical wells are considered marginal, or stripper, wells, which will continue to produce small volumes until they become uneconomic.
In January 2019, Consolidated Edison, Inc., (Con Edison)—the largest utility provider in the New York City area, serving 10 million customers—announced a moratorium on new natural gas connections in most of Westchester County, effective March 16. Demand for natural gas in the New York City area has increased in recent years, leading to concerns about reliability of service. Con Edison claimed it cannot guarantee uninterrupted service to new natural gas connections. Between the announcement of the moratorium and its start on March 16, Con Edison received 1,600 applications for firm natural gas service in the moratorium area. Customers on firm natural gas service contracts have delivery priority above those on interruptible contracts.
Despite an increase in natural gas production in the Northeast, regional demand for natural gas—driven both by population growth and switching from heating oil—has grown even faster, causing concern about the ability to provide service to new customers. During recent winters, natural gas utilities in the Northeast have been using most, if not all, available pipeline capacity to transport natural gas to demand centers.
Con Edison is also actively pursuing strategies to further alleviate interstate natural gas pipeline constraints, such as using electricity for heating and cooking, providing energy efficiency rebates, and creating demand response programs.