10 Desain Iklan Paling Kreatif dan Menarik di Seluruh Dunia

EIA’s July 2018 Short-Term Energy Outlook (STEO) expects natural gas-fired power plants to supply 37% of U.S. electricity generation this summer (June, July, and August), near the record-high natural gas-fired generation share in summer 2016. EIA forecasts the share of generation from coal-fired power plants will drop slightly to 30% in summer 2018, continuing a multi-year trend of lower coal-fired electricity generation. The share of electricity generation supplied by natural gas-fired power plants has increased over the past decade, while the share supplied by coal has fallen, primarily as a result of sustained low natural gas prices, increases in natural gas-fired capacity, and retirements of coal-fired generating capacity. Over the three-year period from 2015 to 2017, the cost of natural gas delivered to electric generators averaged $3.16 per million Btu (MMBtu), compared with $7.69/MMBtu between 2006 and 2008. The combination of relatively low natural gas prices, environmental regulations, and supportive renewable energy policies has led the industry to build new natural gas-fired and renewable capacity and to retire coal-fired power plants. As reported on EIA’s Preliminary Monthly Electric Generator Inventory, power plant operators added 5.4 gigawatts (GW) of new natural gas-fired generating capacity during the first four months of 2018 with an additional 15 GW scheduled to come online through the end of the year. This addition would be the largest increase in natural gas capacity since 2004. The electric industry also added 2.6 GW of new utility-scale solar and wind generating capacity during the first four months of the year, with an additional 9.6 GW scheduled to come online by the end of 2018. More than 10 GW of coal-fired capacity was retired over the 12-month period ending April 2018. EIA forecasts the delivered cost of natural gas will average $3.16/MMBtu this summer, 2% lower than the average cost during the summer of 2017. In contrast, the cost of coal delivered to electric generators is forecast to rise slightly this summer. The continued low cost of natural gas, along with the recent additions of natural gas-fired capacity and retirements of coal power plants, drive EIA’s expectation that natural gas will contribute a growing share of electricity generation this summer, while coal's share will fall. The largest changes in generation shares occur in the Midwest census region. During the summer of 2018, EIA expects natural gas will supply 20% of electricity in the Midwest, up from 15% last summer. The forecast share of generation from coal in the Midwest falls from 53% last summer to 49% this summer. Unlike the rest of the country, natural gas generation in the West census region is forecast to decline this summer as renewable energy generating capacity increases. Nearly 2 GW of utility-scale solar generating capacity came online in the West census region during the 12 months ending in April. EIA forecasts the share of generation in the West from renewable sources other than hydropower will increase to 16% in summer 2018, up from 14% last summer.

In 2017, more U.S. crude oil was sent to China than any other destination except Canada. China received more U.S. crude oil in 2017 than the third- and fourth-largest importers, the United Kingdom and Netherlands, combined. China has been the world’s largest net importer of total petroleum and other liquid fuels since 2013 and surpassed the United States as the world’s largest gross crude oil importer in 2017. Based on data through April, China’s imports of U.S. crude oil have continued to increase, averaging 330 thousand barrels per day (b/d) in 2018. In February 2018, China received more U.S. crude oil than any other destination. Nearly all of these crude oil exports were sent from the U.S. Gulf Coast region. China was the third-largest destination for U.S. propane exports in 2017, behind only Japan and Mexico. Overall, about half of U.S. propane exports went to Asian countries in 2017, displacing supplies from Middle Eastern countries and some regional production of propane. Propane is used in many Asian countries as a feedstock for producing ethylene and propylene, building blocks for chemical and plastic manufacturing. So far in 2018, China has remained the third-largest destination for U.S. propane exports, receiving 92 thousand barrels per day through April, or 31% less than U.S. propane exports to China in the first four months of 2017. the third-largest importer of U.S. LNG exports behind Mexico and South Korea. The next-largest importer, Japan, received about half as much U.S. LNG in 2017 as China. In 2017, China surpassed South Korea to become the second-largest importer of LNG in the world. Based on data through April 2018, China’s imports of U.S. LNG have averaged 0.4 billion cubic feet per day, behind only South Korea and Mexico. The next-largest importer of U.S. LNG, India, has received less than half as much U.S. LNG as China so far in 2018. China also receives other petroleum product exports from the United States, such as petroleum coke and normal butane. Although China has large domestic supplies of coal, China also imports some coal from the United States. In 2017, China received 3.2 million short tons of U.S. coal, or 3% of total U.S. coal exports, making it the tenth-largest destination for U.S. coal exports. About 90% of China’s 2017 imports of U.S. coal was metallurgical coal used in the production of steel.

Fossil fuels—petroleum, natural gas, and coal—have accounted for at least 80% of energy consumption in the United States for well over a century. The fossil fuel share of total U.S. energy consumption in 2017 was the lowest share since 1902, at a little more than 80%, as U.S. fossil fuel consumption decreased for the third consecutive year. The decline in fossil fuel consumption in 2017 was driven by slight decreases in coal and natural gas consumption. Coal consumption fell by 2.5% in 2017, following larger annual declines of 13.6% and 8.5% in 2015 and 2016, respectively. U.S. consumption of coal peaked in 2005 and declined nearly 40% since then. Natural gas consumption fell by 1.4% in 2017, a change from recent trends. Unlike coal consumption, which has decreased in 8 of the past 10 years, natural gas consumption has increased in 8 of the past 10 years, and in 2017, was twice that of coal. Natural gas consumption growth has been driven by increased use in the electric power sector. Overall, U.S. consumption of natural gas increased by 24% from 2005 to 2017. Petroleum consumption increased in 2017, but remains 10% lower than its peak consumption level, also set in 2005. Mainly used in the transportation sector, several petroleum-based fuels are also used in homes, businesses, and industries. Petroleum has been the largest source of energy consumption in the United States since surpassing coal in 1950. The renewable share of energy consumption in 2017, which includes hydroelectricity, biomass, and other renewables such as wind and solar, was 11.3%, the highest since the late 1910s, when overall energy consumption was lower and biomass consumption—mainly wood—made up a larger share. The largest growth in renewables over the past decade has been in solar and wind electricity generation. Energy consumption in the United States has undergone many changes over the course of the nation’s history, from wood as the primary resource in the 18th and 19th centuries, to the onset of coal and petroleum use, to the more modern rise of nuclear power in the late 20th century, and to renewables in the early 21st century. Of course, EIA did not exist to collect data in 1776. The Monthly Energy Review's pre-1949 estimates of U.S. energy use are deeply indebted to two sources. Much of the data used in earlier energy estimates are from the book Energy in the American Economy 1850-1975, Its History and Prospects by Sam Schurr and Bruce Netschert. The U.S. Department of Agriculture’s Circular No. 641, Fuel Wood Used in the United States 1630–1930, published in 1942, provides some of the earliest biomass consumption estimates for the United States. Appendix D of EIA’s Monthly Energy Review compiles these estimates of U.S. energy consumption in ten-year increments from 1635 through 1845 and five-year increments from 1845 through 1945. Data for 1949 through the present day can be found in the latest Monthly Energy Review.

The Electric Reliability Council of Texas (ERCOT), grid operator for most of the state of Texas, estimates a reserve margin of 11% for this summer—lower than previous years and ERCOT’s 13.75% reference reserve margin—indicating a smaller cushion of resources to meet summer peak demand and an increased risk of grid stress conditions. The lower anticipated reserve margin is mainly a result of three large coal plants retiring in early 2018 and forecasts of record-breaking summer electricity demand. Although ERCOT is only expecting a slightly hotter-than-normal summer overall, abnormally hot stretches of weather in May and June have already set new monthly demand records. Hourly day-ahead prices at ERCOT’s North hub, which represents a region that includes the Dallas-Fort Worth area, reached $551 per megawatthour (MWh) on May 16 and 15-minute real-time prices reached $3,125/MWh on June 5, reflecting the dynamic needs of the grid during these unexpectedly high electricity demand periods. Reserve margins are projections of how much additional or reserve capacity is available beyond the amount needed to meet expected peak loads. These projections usually incorporate conservative estimates of factors such as the expected contribution of wind and solar resources during peak hours and demand reductions from load resources such as demand response programs. ERCOT’s final seasonal assessment of the anticipated reserve margin for the summer increased to 11% from earlier projections of 9.3% after a new generator moved up its online date, a mothballed generator became available, and a switchable generator that can choose to connect to either ERCOT or Southwest Power Pool became available to ERCOT. Reserve margin estimates from different sources can vary because of differences in the definitions of factors included in the calculations. Driven by continued growth of the Texas economy, ERCOT is again predicting record-breaking summer electricity demand, as it has for the past two summers, with a peak load forecast of 72,756 megawatts (MW) based on normal weather conditions. This forecast is more than 1,600 MW higher than the current all-time peak of 71,110 MW set in August 2016. While May 2018 was one of the hottest Mays on record for Texas, leading to a new May demand record that was more than 8,000 MW higher than the previous record, the June-August summer period is only expected to be slightly hotter than normal. Unlike most regional transmission organizations, ERCOT does not have a capacity market. Capacity markets compensate generators and sometimes load resources for providing mainly capacity (and not energy) to the grid, although some capacity markets do have energy-related performance requirements. Consequently, ERCOT relies entirely on its energy market and energy prices to send accurate market signals about the grid’s need for additional capacity or generator capabilities and to provide adequate revenues to ERCOT generators because they are not receiving capacity payments. During the high temperatures in May, ERCOT issued several operating condition notices (OCNs) to signal the anticipation of possible emergency conditions; however, the grid operator maintained grid reliability without needing to take any further emergency procedure steps. The May and June price spikes in the day-ahead and real-time markets reflect the dynamically changing conditions of the grid. From day to day and on a real-time (hourly and sub-hourly) basis, the short-term needs of the grid can change quickly and depend on many factors, including the level of demand, the amount of generator outages, and the availability of resources to provide energy, ancillary services, and additional capacity to the grid. Three large coal plants retired in early 2018: the 1,865-MW Monticello plant; the 1,200-MW Sandow (4 & 5) plant; and the 1,208-MW Big Brown plant. These coal plants made up 4,273 MW of generation capacity, about 20% of coal capacity and 4% of total electricity generating capacity in ERCOT at the end of 2017. Before these coal plant retirements, most of the recent power plant retirements in ERCOT have been smaller and older natural gas steam plants that were built in the 1950s through 1970s, with some dating as early as the 1920s. The Monticello, Sandow, and Big Brown plants were all built in the 1970s or 1980s with some generating units added or upgraded as recently as 2010.

The Electric Reliability Council of Texas (ERCOT), grid operator for most of the state of Texas, estimates a reserve margin of 11% for this summer—lower than previous years and ERCOT’s 13.75% reference reserve margin—indicating a smaller cushion of resources to meet summer peak demand and an increased risk of grid stress conditions. The lower anticipated reserve margin is mainly a result of three large coal plants retiring in early 2018 and forecasts of record-breaking summer electricity demand. Although ERCOT is only expecting a slightly hotter-than-normal summer overall, abnormally hot stretches of weather in May and June have already set new monthly demand records. Hourly day-ahead prices at ERCOT’s North hub, which represents a region that includes the Dallas-Fort Worth area, reached $551 per megawatthour (MWh) on May 16 and 15-minute real-time prices reached $3,125/MWh on June 5, reflecting the dynamic needs of the grid during these unexpectedly high electricity demand periods. Reserve margins are projections of how much additional or reserve capacity is available beyond the amount needed to meet expected peak loads. These projections usually incorporate conservative estimates of factors such as the expected contribution of wind and solar resources during peak hours and demand reductions from load resources such as demand response programs. ERCOT’s final seasonal assessment of the anticipated reserve margin for the summer increased to 11% from earlier projections of 9.3% after a new generator moved up its online date, a mothballed generator became available, and a switchable generator that can choose to connect to either ERCOT or Southwest Power Pool became available to ERCOT. Reserve margin estimates from different sources can vary because of differences in the definitions of factors included in the calculations. Driven by continued growth of the Texas economy, ERCOT is again predicting record-breaking summer electricity demand, as it has for the past two summers, with a peak load forecast of 72,756 megawatts (MW) based on normal weather conditions. This forecast is more than 1,600 MW higher than the current all-time peak of 71,110 MW set in August 2016. While May 2018 was one of the hottest Mays on record for Texas, leading to a new May demand record that was more than 8,000 MW higher than the previous record, the June-August summer period is only expected to be slightly hotter than normal. Unlike most regional transmission organizations, ERCOT does not have a capacity market. Capacity markets compensate generators and sometimes load resources for providing mainly capacity (and not energy) to the grid, although some capacity markets do have energy-related performance requirements. Consequently, ERCOT relies entirely on its energy market and energy prices to send accurate market signals about the grid’s need for additional capacity or generator capabilities and to provide adequate revenues to ERCOT generators because they are not receiving capacity payments. During the high temperatures in May, ERCOT issued several operating condition notices (OCNs) to signal the anticipation of possible emergency conditions; however, the grid operator maintained grid reliability without needing to take any further emergency procedure steps. The May and June price spikes in the day-ahead and real-time markets reflect the dynamically changing conditions of the grid. From day to day and on a real-time (hourly and sub-hourly) basis, the short-term needs of the grid can change quickly and depend on many factors, including the level of demand, the amount of generator outages, and the availability of resources to provide energy, ancillary services, and additional capacity to the grid. Three large coal plants retired in early 2018: the 1,865-MW Monticello plant; the 1,200-MW Sandow (4 & 5) plant; and the 1,208-MW Big Brown plant. These coal plants made up 4,273 MW of generation capacity, about 20% of coal capacity and 4% of total electricity generating capacity in ERCOT at the end of 2017. Before these coal plant retirements, most of the recent power plant retirements in ERCOT have been smaller and older natural gas steam plants that were built in the 1950s through 1970s, with some dating as early as the 1920s. The Monticello, Sandow, and Big Brown plants were all built in the 1970s or 1980s with some generating units added or upgraded as recently as 2010.