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Siapa sih yang gak doyan pergi kelaut. Bahaya tidak memandang bulu, baik itu laki-laki atau perempuan, tua atau muda. Electric power sector consumption of fossil fuels at lowest level since 1994 U.S. electric power sector consumption of fossil fuels, as explained in the article text Source: U.S. Energy Information Administration, Monthly Energy Review Fossil fuel consumption in the electric power sector declined to 22.5 quadrillion British thermal units (quads) in 2017, the lowest level since 1994. The declining trend in fossil fuel consumption by the power sector has been driven by a decrease in the use of coal and petroleum with a slightly offsetting increase in the use of natural gas. Changes in the fuel mix and improvements in electricity generating technology have also led the power sector to produce electricity while consuming fewer fossil fuels. In 2017, coal consumption by the electric power sector reached its lowest level since 1982, and petroleum consumption in the power sector was the lowest on record, based on data since 1949. Recent natural gas consumption in the power sector has generally been increasing, but 2017 consumption was slightly lower than the record-high 2016 level. In energy-equivalent terms, more coal was consumed in the power sector than natural gas in 2017, at 12.7 quads and 9.5 quads, respectively. However, in terms of electricity generation, natural gas-fired power plants in the electric power sector produced more electricity than coal-fired plants, at 31% and 30% of the U.S. total, respectively, in 2017. Natural gas-fired units tend to be more energy efficient, requiring less energy content to produce a unit of electricity. As recently as 2000, natural gas-fired power plants were on average about as efficient as coal-fired plants. Since then, new natural gas-fired power plants have tended to use combined-cycle generators, which are more efficient because the waste heat from the gas turbine is routed to a nearby steam turbine that generates additional power. Combined-cycle units now make up most of the natural gas-fired electricity generation capacity. By the end of 2018, natural gas combined-cycle units may surpass conventional coal-fired power plants to become the most prevalent technology for generating electricity in the United States. As the natural gas-fired generation fleet has grown and become more efficient, the generation-weighted average efficiency of fossil fuel-fired electricity generation has improved. In 1994, fossil fuel power plants required 10,400 British thermal units (Btu) of primary energy to produce each kilowatthour (kWh); by 2017 that rate had fallen to 9,400 Btu/kWh. U.S. net electricity generation and heat rates from fossil fuels, as explained in the article text Source: U.S. Energy Information Administration, Monthly Energy Review These changes in energy consumption and efficiency have also affected carbon dioxide (CO2) emissions from the electric power sector, which in 2017 were the lowest since 1987. Because coal combustion is much more carbon intensive than natural gas combustion, CO2 emissions from coal were more than double those from natural gas in 2017, even though natural gas provided more electricity generation. U.S. carbon dioxide emissions from electric power sector fossil fuels, as explained in the article text Source: U.S. Energy Information Administration, Monthly Energy Review More information on U.S. energy consumption and CO2 emissions across sectors is available in EIA’s Monthly Energy Review. EIA’s residential energy survey now includes estimates for more than 20 new end uses residential electricity consumption by end use, as explained in the article text Source: U.S. Energy Information Administration, 2015 Residential Energy Consumption Survey Results from the 2015 Residential Energy Consumption Survey (RECS) introduced estimates of energy consumption for an expanded list of energy end uses. For electricity, the number of end uses estimated has expanded from 4 to 26 by adding estimates for equipment such as dishwashers, clothes washers, clothes dryers, televisions, and lighting. From 1990 through 2009, RECS estimated consumption and expenditures for four end-use categories: space heating, air conditioning, water heating, and refrigerators; the remainder was aggregated as other. As certain appliances and equipment have become more prevalent in homes, this remainder category became a larger share of residential energy consumption, especially for electricity. In 2015, nearly half of residential electricity consumption fell into the other category. Adding several new characterizations of end uses provides a better accounting of energy use in homes, and now RECS attributes only 13% of residential electricity consumption to end uses not elsewhere classified. The expanded end-use categories that consume electricity vary widely in how much energy they consume and how commonly they are found in the 118 million U.S. homes that are occupied as a primary residence. Lighting is used in all homes and consumes a substantial share of electricity—10% of the total electricity used in homes. Nearly every home had a television in 2015; about 3% of homes had no television. Televisions and their associated peripheral devices such as set top boxes and internet streaming devices use 7% of the electricity used in homes each year. Other equipment is relatively less common but can account for a larger share of electricity consumption in the homes that have them. For example, only 7.9 million homes, or about 7% of the national total, reported using a pool pump. Nationwide, pool pumps consume 1% of the electricity used in homes, but among homes that have pool pumps, the equipment consumes 8% of total electricity used each year. Refrigerator energy consumption and expenditures have been reported since the 1990 RECS. The 2015 estimates provide additional detail to this category, with separate estimates for the most-used and, in the homes that have them, the second-most-used refrigerator in a home. As a group, refrigerators use 7% of the electricity consumed. Most energy consumed for refrigeration is consumed by most-used refrigerators in homes (77%), with second refrigerators using 18% of total refrigeration consumption nationwide. New estimates are also available for other common electric appliances, including clothes dryers (5% of total electricity consumption); microwaves (1%); dishwashers (1%); and cooking (1%), which collectively covers stoves, ovens, and cooktops. For dishwashers and clothes washers, the estimates cover only the electricity used to operate the equipment and not the energy used to heat the water drawn by these appliances; that energy would be accounted for in the estimate for water heating. These end uses and several other itemized estimates collectively cover 87% of residential electricity use. The remaining category not elsewhere classified combines a number of end uses that are not publishable individually, such as computers, smartphones, and small kitchen appliances, as well as consumption from end uses not captured on the RECS Household Survey. Before 2015, RECS surveys used statistical regression models to disaggregate a home’s energy consumption across the five published end uses. With the 2015 study, EIA transitioned to engineering models, which incorporate more equipment information and usage behavior from the RECS Household Survey as well as from research and equipment specifications, which produced improved estimates of energy consumption of devices in homes. This improvement in methods for energy allocation affects comparisons with previous RECS. To assist data users interested in analyzing the time series of end-use consumption, EIA has published a brief report describing how this change in methodology has affected end-use estimates. EIA has also updated the methodology report for this survey to provide more information on the consumption data collection and end-use estimation approach. More detail is also available for natural gas and propane end uses. For natural gas, the 2015 RECS provides expanded estimates for natural gas cooking, clothes dryers, pool heaters, and hot tub heaters. For propane, the new end uses detailed are clothes dryers and cooking. These data are available in tables as well as in a microdata file.

Southern California’s natural gas infrastructure may face constraints this summer daily SoCalGas system sendout, as explained in the article text Source: U.S. Energy Information Administration, based on Southern California Gas Company and Aliso Canyon Technical Assessment Group Updated to correct pipeline maintenance schedule. 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. map of Southern California, as explained in the article text Source: U.S. Energy Information Administration and Southern California Gas Company 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. daily socalgas natural gas inventories, as explained in the article text Source: U.S. Energy Information Administration, based on SoCalGas ENVOY electronic bulletin board system and California Public Utilities Commission 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.

Capital costs for large-scale battery storage systems installed across the United States differ depending on technical characteristics. Systems are generally designed to provide either greater power capacity (a battery’s maximum instantaneous power output) or greater energy capacity (the total amount of electricity that can be stored or discharged by a battery system). The cost of a battery system can be expressed in terms of power capacity costs (dollars spent per unit of maximum instantaneous power output as expressed in dollars per kilowatt) or energy capacity costs (dollars spent per unit of total energy stored as expressed in dollars per kilowatthour), depending on which attribute is prioritized. Power-oriented systems are shorter duration systems, meaning they are typically designed to generate large amounts of instantaneous power output but cannot sustain that output for very long. These systems have lower costs per kilowatt and higher costs per kilowatthour. For example, a $12 million battery system with a nameplate power capacity of 10 megawatts and nameplate energy capacity of 4 megawatthours would have relatively low power costs ($1,200 per kilowatt) and relatively high energy costs ($3,000 per kilowatthour). Power-oriented systems are designed to provide grid reliability services such as frequency regulation, which requires large shifts in the power capacity in quick, sub-hourly intervals. Power-oriented battery systems are more prevalent in the PJM Interconnection than other regions and actively participate in PJM’s ancillary services market. Energy-oriented systems are designed for use for longer durations, meaning they have more energy capacity relative to their power capacity. As a result, these systems have higher average costs per kilowatt and lower costs per kilowatthour. For example, an $8 million battery system with a nameplate power capacity of 4 megawatts and nameplate energy capacity of 10 megawatthours would have relatively high power costs ($2,000 per kilowatt) and relatively low energy costs ($800 per kilowatthour). Energy-oriented battery systems are used to provide services such as peak load shaving, which is the act of delivering power during periods of the highest electricity demand, typically over the course of one or more hours. Energy-oriented battery systems are relatively more popular in the California Independent System Operator (CAISO) area. The nameplate duration of the battery storage system is the ratio of nameplate energy capacity to nameplate power capacity. For example, a system with a 6-megawatt power capacity and a 24-megawatthour energy capacity has a nameplate duration of 4 hours. Short-duration batteries—which are power oriented—have durations of less than 30 minutes. Medium-duration battery storage systems have nameplate durations ranging between 30 minutes and 2 hours. Long-duration battery storage systems—which are energy oriented—have more than 2 hours of nameplate duration. EIA’s recently released U.S. Battery Storage Market Trends report explores trends in U.S. battery storage capacity additions and describes the current state of the market, including information on applications and cost, as well as market and policy drivers.