Warga Penasaran Banyak Monyet Melihat ke Bawah Sumur, Ternyata Dalamnya Ada

one-third, from $2,361 per kilowatt (kW) to $1,587/kW, based on analysis in the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy’s (DOE/EERE) Wind Technology Market Report. The reasons for this decline include improving technology and manufacturing capability and an increasing concentration of builds in the regions of the United States with the lowest installation costs. After many years of declining real project costs, wind reached a low in 2004 at $1,342/kW. Through the remainder of that decade, costs gradually increased, reaching a peak in 2009 and 2010 of about $2,360/kW. Contributing factors to the increasing costs through 2010 included increasing labor costs, an increase in the cost of key manufacturing and construction commodities, and international currency exchange fluctuations affecting imports of key equipment. After 2010, installed costs began to decline as some of those pressures lifted. The global recession of 2008 reduced the cost of key construction and manufacturing commodities. Domestic manufacturing capacity for wind turbine components increased, and the increasing pace of installations helped to reduce both turbine manufacturing and installation costs through learning-by-doing effects, even as higher-performing equipment continued to enter the wind turbine market. Regional variations in wind turbine installation costs also have an effect on reported U.S. average costs. In 2010, the Interior region of the United States had an average installation cost of $2,069/kW, compared with $2,247/kW for the rest of the country. By 2016, the costs in the Interior had dropped 25% from 2010 levels to $1,531/kW, and costs in the rest of the United States had dropped 10% to $2,025/kW. EIA began collecting capital cost data for new generators in 2013, and this data closely tracks the estimates from DOE/EERE. Also in 2010, the share of wind capacity installations was almost evenly split between the Interior and the rest of the United States, with only 46% of capacity entering service that year in the Interior. By 2016, almost 90% of incremental capacity was installed in the lower-cost Interior region. This capacity takes advantage of not only the more favorable wind resources of the region, but also the easily developed expanses of flat land (allowing for larger project sizes) and transportation access to the developing concentration of turbine component manufacturing in this region. The increasing concentration of U.S. wind builds in the low-cost Interior region of the country has reinforced the overall decline in the average cost of wind construction. Because of the recent increase in the overall capacity mix in this region, the national rate of decline in wind costs closely tracks the cost declines for the Interior. Although other factors have affected overall costs, 2016 average installed costs for wind in the United States would have been more than 10% higher if total wind installations had remained at their 2010 geographic market shares.

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.

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 North American Electric Reliability Corporation's (NERC) recent 2018 Summer Reliability Assessment finds that there are enough resources to meet this summer's projected peak electricity demand in in all areas of the country except the Electric Reliability Council of Texas (ERCOT). Anticipated reserve margins—the amount of expected unused electric generating capacity at the time of peak load—range from a little less than 11% in ERCOT to about 33% in PJM Interconnection (PJM). In the absence of cost-effective, large-scale electricity storage, reliability of the nation’s electric power system requires that electricity be available to meet consumption at any moment. NERC, a nonprofit corporation that oversees regional electric reliability entities in the Lower 48 United States, Canada, and parts of Mexico, publishes a summer reliability report that presents peak electricity demand and supply changes and highlights any unique regional challenges or expected conditions that might affect the bulk power system. An important metric of electric reliability is the anticipated reserve margin, measured as anticipated resources (capacity) minus net internal demand, expressed as a percentage of net internal demand. Net internal demand reflects the total internal demand minus demand response systems that are expected to be available during a peak demand hour. A reserve margin of 15% means that about 15% of a region’s electric generating capacity would be available as a buffer to meet the summer’s peak hourly load in case of unforeseen generation or transmission outages. here/a> Planning Reference margins, which differ by region, are reserve margin targets based on each area's load, generation capacity, and transmission characteristics. In some cases, the planning reference margin level is a requirement implemented by states, provinces, independent system operators, or other regulatory bodies. Reliability entities in each region aim to have their anticipated reserve margins surpass their planning reference margins, which are generally set near 15% in most regions. All U.S. regions in NERC’s Summer Reliability Assessment have anticipated reserve margins that are higher than their planning reference margins with the exception of ERCOT. With 78,146 megawatts (MW) of anticipated resources this summer, ERCOT projects an anticipated reserve margin of 10.9%, which equates to a capacity shortfall of about 2,000 MW, based on its planning reference margin of 13.75%. Anticipated reserve margins are highest in the PJM and Southwest Power Pool (SPP), where reserve margins exceed 32%. Reserve margins that are significantly in excess of target levels, although helpful for reliability, indicate the region may have an excess generation capacity. Demand response resources play an important role in electric reliability. Demand response involves the targeted reduction of electricity use during times of high demand when resources are limited. For example, contracts between utilities and customers may allow power system operators to temporarily turn off some air conditioning equipment or industrial processes during demand response events. In return, customers receive incentives for these reductions. Based on data compiled by NERC, demand response resources range from 6% of total internal demand in areas such as the PJM Interconnection and Florida Reliability Coordinating Council to less than 2% in ISO New England and SPP.