Kakek Pencari Sampah Temukan Bongkahan Aneh, Saat Digali Ia Menjadi Kaya Raya!

Spending on electricity distribution systems by major U.S. electric utilities—representing about 70% of total U.S. electric load—has risen 54% over the past two decades, from $31 billion to $51 billion annually. This increase has been largely driven by increases in capital investment. From 1996 to 2017, annual capital investment by these utilities for electric distribution systems nearly doubled, which was similar to increases in transmission investment over the same time period. Annual spending on customer expenses and operations and maintenance by these utilities also increased slightly. This information is based on reports to the Federal Energy Regulatory Commission (FERC) from major utilities. The electricity distribution system works to decrease voltage from high-power transmission lines and to deliver electricity to homes and businesses. Electric distribution spending is affected by the number of customers served, the amount of electricity sold, the number of miles of electric distribution wire installed (line miles), and the maximum amount of load on the lines at one time (peak load). Electric distribution system costs have been increasing faster than the growth of any of the other variables. Capital investment accounts for the largest share of distribution costs as utilities work to upgrade aging equipment. According to a 2015 U.S. Department of Energy report, 70% of power transformers are 25 years of age or older, 60% of circuit breakers are 30 years or older, and 70% of transmission lines are 25 years or older. Poles, wires, and substation transformers are being upgraded with advanced materials and new technology to better withstand extreme weather events, to allow easier frequency and voltage control during system emergencies, and to accommodate greater use of variable renewable generation (customer-sited wind and solar). Over the past decade, investment in overhead poles, wires, devices, and fixtures such as sensors, relays, and circuits has risen by 69%, and spending on substation transformers and other station equipment has increased by 35%. Investment in customer meters has more than doubled over the past decade as utilities have upgraded customer meters to smart meters that can be accessed remotely, communicate directly to utilities, and support smart consumption and pricing applications using real-time or near real-time electricity data. Customer-related expenses include advertising, reading meters, billing, and communicating with customers. Although expenses related to customer accounts and sales have decreased, spending on customer services and information systems has more than doubled over the past decade in an effort to better inform customers about outage locations and durations and to develop better customer outreach tools. Operations and maintenance (O&M) expenses have increased as electric distribution systems experience stress from several factors, including more customers, variable generation, and the effects of storms, wildfires, and flooding. Managing a grid with increasing amounts of customer-sited variable generation increases wear and tear on the distribution equipment required to maintain voltage and frequency within acceptable limits and to manage excessive heating of transformers during reverse power flow. According to FERC, the largest spending increases have occurred in the older, more populated systems, which include the Northeast Power Coordinating Council (New York City and Boston), Reliability First (Chicago, Detroit, Philadelphia, Baltimore-Washington, DC), and the Western Electricity Coordinating Council (Los Angeles, San Francisco).

Continuing eruptions in lower Puna, the southeastern corner of the island, have damaged transmission lines and equipment, and local residences are experiencing extended power outages. The island’s utility, Hawaii Electric Light Co (HELCO), has implemented switching operations to reroute power from its nearby plants to customers in undamaged areas of lower Puna. PGV is a geothermal plant drawing steam and hot geothermal fluid up through 11 production wells drilled 6,000 feet to 8,000 feet deep. Pressurized steam from the hot fluid, along with non-condensable gases, is routed through the facility to drive a turbine generator that produces electricity. Exhaust steam from the turbine is used to vaporize a working fluid, which drives a second turbine that generates additional electricity. The remaining steam (along with geothermal fluid) is reinjected into the ground through reinjection wells. Plant operators quenched 10 of the 11 geothermal wells to prevent them from releasing gases. Quenching involves injecting the well with water to cool and depressurize it. The 11th well was plugged with bentonite clay after quenching efforts were unsuccessful. Two of the capped geothermal wells, identified as KS-5 and KS-6, were covered by lava from the Kilauea fissures in late May. A transmission substation and a warehouse containing a drilling rig were also destroyed by the lava flows. PGV's generating capacity of 25 MW when it opened in 1993 was expanded to 30 MW in 1995 and then to 38 MW in 2012. In March 2018, the facility owner announced plans to increase capacity to 46 MW by 2020. The plant is the largest renewable power plant on the island. More than half of the island’s power generation mix is fueled by petroleum, based on EIA data for 2016. The remaining 44% is from various renewable sources. Of these, geothermal (20% of the island’s generation mix) is the largest, followed by wind (11%), small-scale solar photovoltaic (9%), and hydropower (5%).

Between 2010 and 2016, the capacity-weighted average cost (real 2016$) of U.S. wind installations declined by 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.

HALAMAN SELANJUTNYA: