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Consumption of hydrocarbon gas liquids (HGL) in the United States totaled 928 million barrels in 2016, up about 12% since 2010. During the same time, total U.S. HGL prices fell by 47% and, consequently, expenditures decreased by about 41%. In 2016, total U.S. HGL expenditures were $32 billion, the lowest since 2003. The Texas and Louisiana industrial sectors dominate HGL consumption, expenditures, and price formation in the United States. The two states combined to account for about 75% of total U.S. HGL consumption and 58% of total U.S. HGL expenditures in 2016, almost all of which was in the industrial sector. The HGL pricing hub in Mont Belvieu, Texas, heavily influences the prices of HGL products across the nation. EIA’s State Energy Data System (SEDS) recently published a new categorization of petroleum products with annual state-level estimates of HGL consumption, prices, and expenditures by end-use sector for 1960 through 2016. HGLs include natural gas liquids (ethane, propane, normal butane, isobutane, and natural gasoline) and refinery olefins (ethylene, propylene, normal butylene, and isobutylene). Almost all HGLs not used as refinery and blender inputs are consumed exclusively in the industrial sector, with the exception of propane, which is consumed in all sectors. The industrial sector is the largest consumer of HGLs in the United States, accounting for about 83% of total U.S. HGL consumption in 2016. Industrial consumption of HGLs is primarily for feedstocks in the production of intermediate organic chemicals such as ethylene and propylene, which are used to make plastics and resins. Industrial sector HGL consumption increased by 125 million barrels, or about 19%, between 2010 and 2016. Over the same time, industrial HGL expenditures decreased by more than $17 billion (45%), as the average U.S. price of industrial HGLs decreased from $16.64 per million British thermal units (Btu) in 2010 to $7.79 per million Btu in 2016. The residential sector, the second-largest HGL-consuming sector, is the only sector to decrease consumption between 2010 and 2016. Residential sector HGL consumption, primarily consumer-grade propane for space heating, water heating, and cooking, was 112 million barrels in 2016, a 19% decrease from 2010. Lower residential consumption of propane was attributed to warmer winter temperatures in 2016 relative to 2010 and to the decline in total households reporting propane as a primary heating fuel. Residential HGL expenditures decreased by about 32% as the average U.S. price of residential HGL decreased from $25.68 per million Btu in 2010 to $21.59 per million Btu in 2016. The commercial sector and the transportation sector consume relatively small amounts of HGLs, accounting for 4% and 1% of total HGL consumption, respectively, in 2016. The commercial sector consumes propane as a heating fuel, and the transportation sector uses propane for fueling alternative-fueled vehicles, such as propane-fueled police cars and school buses. The next largest HGL-consuming states are Illinois and Iowa, consuming 21 million and 19 million barrels, respectively, in 2016. Only five states—Texas, Louisiana, Illinois, Iowa, and Kentucky—have ethylene crackers that consume ethane as a feedstock. The largest residential HGL-consuming state is Michigan, with about 8% of total U.S. residential consumption in 2016. California, Wisconsin, New York, and Minnesota are the next largest residential HGL consumers, each with about 5% of total U.S. residential HGL consumption. Louisiana, despite being one of the largest HGL-consuming states, consumes relatively little HGL in the residential sector, because most home heating is fueled by electricity and the state has modest heating demand.

Natural gas combined-cycle plants accounted for 10.1 GW, or 40%, of the total proposed capacity that had been scheduled to come online in 2017. Of this amount, 7.5 GW came online within the year, and 2.6 GW were delayed until 2018. Renewable energy technologies—wind and solar (PV) generation—represented the next two largest groups of capacity additions in 2017. Of the 6.9 GW of onshore wind turbines scheduled to come online in 2017, 86% came online as scheduled in 2017; 792 megawatts (MW) were delayed and 155 MW were canceled. About 3.9 GW of utility-scale solar photovoltaic capacity were completed on schedule last year, and 1.2 GW were delayed to 2018 or beyond. Near-term expectations for projects coming online tend to be more accurate than longer term expectations for projects coming online. The information reported to EIA at the end of 2013 for what would be installed in the subsequent year was very similar to what was actually installed in 2014, with a difference of only 200 MW, or about 1% of the total. In later years, however, actual installations differed from the end-of-2013 expectations, as more than 10 GW of capacity came online during 2014 through 2017 that was not anticipated in 2013 EIA-860 reporting. Notable capacity differences in some technologies such as wind and solar can be attributed to changes in subsidies, faster installation times, and decreasing costs. These factors influenced both the timing and magnitude of wind and solar capacity additions. Nuclear capacity additions also faced delays: at the end of 2013, the Watts Bar Unit 2 plant in Tennessee was expected to come online in 2015, and two other nuclear plants were expected to come online in 2017. In reality, Watts Bar Unit 2 came online in June 2016, and the other two projects (Vogtle Units 3 and 4 in Georgia and Virgil C. Summer Units 2 and 3 in South Carolina) were delayed indefinitely.

U.S. electric utilities reported spending $3.6 billion on energy efficiency customer incentives in 2016, or an average of $24 per customer, according to EIA’s survey of electric power sales, revenue, and energy efficiency (EIA-861). Energy efficiency spending is reported on an incremental basis, reflecting new programs operating for the first time in 2016 (including start-up costs) or new participants in existing programs. Most reported spending supported residential and commercial energy efficiency: 43% of spending targeted residential customers, and 49% targeted commercial customers. The remaining 8% of spending targeted industrial customers. Average reported spending per customer varied by state, from $0 in Alaska to $128 in Massachusetts. High-spending states and low-spending states tend to be concentrated in particular regions. By U.S. census region, average utility spending ranged from $11 per customer in the South to $47 per customer in the Northeast. Spending also was higher in certain states with high electricity prices, such as Hawaii, or in certain states with climates that require more energy for heating and cooling, such as Illinois and Arizona. Incremental savings as a result of energy efficiency spending for reporting year 2016 totaled 27.5 billion kilowatthours, or 0.7% of nationwide retail electricity sales. Projected lifecycle savings were much greater, at 354 billion kilowatthours over the lifetime of the efficiency measures used, because some measures that affect heating, cooling, and water heating equipment can provide benefits for several years. Like spending, most savings occurred in the residential and commercial sectors. Annual incremental savings also varied by state, from near 0% of electricity retail sales in Kansas and Alaska to 3% of retail sales in Massachusetts and Rhode Island. Average electricity savings by U.S. census region was the highest at 1.2% in the Northeast, and the lowest at less than 0.4% in the south. Utility energy efficiency incentives can be financial, such as subsidies and rebates for energy efficient equipment, or educational, such as technical assistance, audits, or home energy scores. Behavioral energy efficiency programs, such as home energy use reports, employ messaging to alter consumer behavior. Incentives can be offered to building owners, building occupants, contractors, or upstream or mid-stream retailers, among others. Support for efficient lighting options such as light-emitting diodes (LED) has produced a large portion of utility energy efficiency savings to date, according to program administrators and regulators such as the California Public Utilities Commission, ISO New England, Efficiency Vermont, Rocky Mountain Power, and the Massachusetts Energy Efficiency Advisory Council. According to the U.S. Environmental Protection Agency’s ENERGY STAR® program, utility subsidies for LED bulbs across the United States typically ranged from $1 to $15 per bulb in 2016. Utility programs also subsidize purchases of energy-efficient heating, ventilation, and air-conditioning equipment; encourage adoption of learning thermostats; or offer whole-building retrofits or upstream programs—programs that offer incentives to manufacturers and distributors that are passed on to customers—according to a 2017 report by the American Council for an Energy-Efficient Economy. Utilities administer energy efficiency programs alongside a variety of other federal, state, and local energy efficiency requirements and incentives. Federal regulations and initiatives include minimum federal appliance efficiency standards and the voluntary ENERGY STAR program, while state initiatives range from mandatory energy efficiency resource standards (EERS) to non-binding goals and pilot programs. EERS-related policies have become an indicator of states with a higher commitment to ongoing energy efficiency actions. Utilities in states with an EERS tend to report significantly more spending and savings than utilities in states with non-binding goals or no programs at all. In states with an EERS, utilities spent $31 on incentives per customer and saved 1.0% of retail electricity sales on average in 2016. In comparison, utilities in states with non-binding goals or pilot programs spent an average of $15 per customer and saved 0.5% of retail sales, and utilities in states with no energy efficiency goals spent $12 per customer and saved 0.4% of retail sales.

Competitive power marketers supplied about 21% of the retail electricity sold in the United States in 2016, up from 11% in 2005. The share of retail electricity sales of regulated investor-owned utilities fell from 62% in 2005 to 52% in 2016. This shift was driven by the Energy Policy Act of 2005, which repealed the Public Utility Holding Company Act of 1935 and closed the original federal regulatory structure established by New Deal-era legislation, which was a combination of public financial reforms and regulations in the 1930s. U.S. retail electricity sales are provided by entities with different ownership structures such as power marketers, cooperatives, government utilities, and investor-owned utilities. Investor-owned utilities (IOUs) have historically been the primary producers and distributors of electricity to retail customers in the United States. Some IOUs are still vertically integrated, meaning they offer generation, transmission, and distribution service. Other IOUs may partner with independent power producers to purchase generation service. IOUs are regulated by state and local agencies and also by federal agencies if they own transmission facilities. Retail consumption of electricity has remained relatively flat in the United States over the past decade, especially in the residential sector, where sales per capita have declined. Total retail sales of electricity provided by IOUs have declined over this period, falling from 2,264 terawatthours (TWh) in 2005 to 1,919 TWh in 2016. The U.S. electricity industry was restructured in the 1990s to increase competition at the wholesale level by breaking up the generation and distribution functions of some vertically integrated utilities. In addition, some states deregulated the retail side of the industry by unbundling the electricity delivery and electricity generation components of retail bills. An increasing number of electricity customers have now obtained access to the competitive retail market, giving them choices in suppliers of electric power. Power marketers act as intermediaries between the retail buyer and the generator. Retail sales of electricity by power marketers have risen dramatically in recent years, growing from 412 TWh in 2005 to 767 TWh in 2016. Power marketers have also expanded their geographic scope: in 2004, 98% of all U.S. power marketer sales were in Texas, but by 2016, power marketers were active in many states. As retail sales provided by IOUs declined, IOUs have less electricity for sale in wholesale power markets. Although the level of generation produced by IOUs declined about 14% from 2005 to 2016, wholesale power purchases by IOUs declined by 45% over the same period.

Regional natural gas infrastructure issues in Southern California could affect electricity reliability this summer, according to separate studies recently released by the Southern California Gas Company (SoCalGas) and the Aliso Canyon Technical Assessment Group. Depending on natural gas infrastructure changes and storage operations this summer, these issues could also have implications for the upcoming winter. The Aliso Canyon Technical Assessment Group, which includes the California Public Utility Commission, the California Energy Commission, the California Independent System Operator, and the Los Angeles Department of Water and Power, concluded that base case total system deliverability capacity—a combination of the natural gas pipeline system and the deliverability capacity of non-Aliso storage working gas—is slightly lower than 3.6 billion cubic feet per day (Bcf/d) this summer, or 0.2 Bcf/d lower than last summer when pipeline outages curtailed deliverability. If daily natural gas demand exceeds 3.6 Bcf/d—which is relatively common in winter months but has occurred only once in the past five summers—some natural gas deliveries to electric generators may need to be curtailed. Since October 2017, SoCalGas has experienced a series of planned and unplanned natural gas pipeline outages that have reduced the ability to bring natural gas into Southern California. According to the May 7, 2018 SoCalGas maintenance schedule, pipeline repairs are not expected to be completed until the end of summer, with key pipelines—Lines 4000, 235-2, and 2000—showing no scheduled completion date. Pipeline capacity for summer 2018 is about 0.53 Bcf/d lower than at this time last summer, but storage deliverability is about 0.4 Bcf/d higher. Natural gas inventories in Southern California are typically refilled over the summer months. However, electricity demand is higher in the summer months, and natural gas is a key fuel source for electric power generation in Southern California. According to SoCalGas, the current outages will create challenges this summer for meeting customer demand while also refilling storage inventories. The timing and extent of refilling natural gas at SoCalGas’ storage fields have changed since a leak at the Aliso Canyon storage complex was discovered in October 2015. Aliso Canyon, previously the second-largest natural gas storage facility in the United States, had its capacity reduced from 86 billion cubic feet (Bcf) to about 25 Bcf as a result of the leak. The total capacity of the four storage facilities in the SoCalGas service territory declined from 136 Bcf to 74 Bcf. Working gas inventories as of June 6, 2018, totaled 58.2 Bcf, which is low by historical standards, but 11 Bcf higher than at this time in 2017 and 4.1 Bcf lower than at this time in 2016. The Assessment Group’s report issued a series of recommendations to help Southern California address reliability challenges, including: Importing liquefied natural gas (LNG) through the Otay Mesa receipt point at the San Diego-Mexico border Coordinating with natural gas customers to ensure they are prepared to respond to high and low operational flow orders to maintain system balance Expediting any pending electricity transmission upgrades Taking advantage of demand response pilot projects Exploring an increase in the maximum target inventory—or storage capacity—at Aliso Canyon EIA provides a daily summary of key energy conditions in Southern California on the Southern California Daily Energy Report. In addition to the daily summary, EIA provides occasional commentary and analysis on notable market conditions in Southern California.