Ada Zohri Ada Pula Jeany Nuraini Si Sprinter Muda Cantik Curi Perhatian Netizen

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).

Trends in the sales shares of new light-duty vehicles by vehicle type have continued as the crossover utility vehicle (CUV) share of light-duty vehicles has increased, largely at the expense of cars, despite increases in gasoline prices over the previous two years. In each month since September 2017, sales of CUVs have exceeded those of cars, a class that includes sedans, hatchbacks, and sports cars. CUVs, which typically have ride height and interior space similar to truck-based sport utility vehicles (SUVs), are built on more fuel-efficient, car-based platforms and often have fuel economies that are only slightly lower than comparable cars. Vehicle sales shares for pickups, SUVs, and other vehicle types—which typically have much lower fuel economy than sedans and many CUVs—have remained relatively constant in recent years, with pickup shares showing comparatively modest gains. Although CUVs and cars are built on similar platforms, CUVs often have slightly lower fuel economy than their comparable sedan counterparts (for example, the Toyota RAV4 CUV versus the Toyota Camry sedan), even when they are equipped with the same engine and transmission. However, the change in vehicle shares from cars to CUVs had less effect on fuel consumption compared with other historical shifts in sales, such as the shift from cars to SUVs in the 1990s and early 2000s. The relatively small variability in annual fuel costs has not been enough to change purchasing trends in the same way that consumers exchanged low fuel economy SUVs for cars and CUVs in the peak of the recession in 2009. At that time, replacing a 20 mile-per-gallon (mpg) vehicle with a 30-mpg vehicle would save an annual 250 gallons when driven 15,000 miles, at a cost savings ranging from $500 ($2/gallon) to $1,000 ($4/gallon). CUVs often have fuel economy ratings that are more comparable to cars than to the fuel economy ratings of SUVs or pickups. Also, as fuel economy increases, cost savings from fuel consumption reductions decrease. For example, a consumer who drives 15,000 miles per year using a 35-mpg sedan consumes about 429 gallons of gasoline annually, while a 30-mpg CUV traveling the same distance would consume 500 gallons, a difference of 71 gallons. That difference in gasoline consumption would cost $143 to $285 annually with gasoline prices in the range of $2/gallon to $4/gallon.

The natural gas spot price spread between the Permian Basin, as priced at the Waha Hub in western Texas, and the U.S. national benchmark Henry Hub in Louisiana has grown considerably in the past year. Natural gas prices at Waha are nearly a dollar per million British thermal units (MMBtu) lower than Henry Hub prices. This spread widened as the ability to transport the increased natural gas production in the Permian Basin in western Texas and southeastern New Mexico was constrained by existing pipeline capacity. Based on estimates in EIA’s most recent Drilling Productivity Report, production of natural gas in the Permian Basin averaged 10.4 billion cubic feet per day (Bcf/d) in June 2018, which was 2.1 Bcf/d more than in June 2017. Much of this increase in production is associated natural gas, or natural gas produced as a byproduct of the increase in oil production from oil-directed rigs. As a result, the increase in natural gas production closely correlated with the increase in crude oil production in the Permian Basin, which averaged 3.3 million barrels per day (b/d) in June 2018, up 0.9 million b/d from the June 2017 level. As Permian Basin oil production grows, producers must find outlets for the associated natural gas. Once pipeline capacity is fully used, choices are limited. The widening price differential between Waha and Henry Hub indicates pipeline capacity is already somewhat constrained. Producers may flare or vent the natural gas, although these disposal methods are regulated in Texas and New Mexico. Both states allow flaring from wells during drilling and immediately after completion. However, after a certain amount of time, producers can only flare natural gas after receiving exemptions from a state agency. If natural gas production continues to grow, and natural gas prices continue to fall, some producers in the area may cease oil production to avoid producing associated natural gas. Two pipelines—Comanche Trail and Trans-Pecos—were completed in 2017 to export Permian natural gas to Mexico. Although these pipelines have a combined takeaway capacity of 2.6 Bcf/d, they are not expected to see significant flows until late 2018 or early 2019 when downstream pipeline infrastructure in Mexico enters service. The only other project expected to come online in 2018 is the combined expansion of the North Texas Pipeline and resumption of service on the Old Ocean Pipeline, which collectively will increase pipeline capacity out of the Permian by 0.15 Bcf/d. Several new pipelines are currently in development to carry natural gas from the Permian Basin to the Gulf Coast: the Gulf Coast Express Pipeline (2.0 Bcf/d capacity), the Permian to Katy Pipeline (1.7 to 2.3 Bcf/d capacity), and the Pecos Trail Pipeline (1.9 Bcf/d capacity). Of these three projects, only the Gulf Coast Express is under construction, with an expected in-service date of October 2019. The proposed pipelines from the Permian Basin are intended to meet Gulf Coast demand for natural gas, which includes new liquefied natural gas export facilities and regional industrial use.

Lava flows from the Kilauea volcano on the island of Hawaii led to the shutdown of the Puna Geothermal Venture (PGV) power plant on May 3, 2018. The 38-megawatt (MW) facility is the only geothermal plant on the island, and it produced about 29% of the island’s electricity generation in 2017. The plant voluntarily ceased operations ahead of the approaching lava flow. 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%).

As of January 1, 2018, U.S. operable atmospheric crude distillation capacity totaled 18.6 million barrels per calendar day (b/cd), a slight decrease of 0.1% since the beginning of 2017 according to EIA’s annual Refinery Capacity Report. Annual operable crude oil distillation unit (CDU) capacity had increased slightly in each of the five years before 2018. Refinery capacity is measured in two ways: barrels per calendar day and barrels per stream day. Barrels per calendar day reflect the input that a distillation unit can process in a 24-hour period under usual operating conditions, taking into account both planned and unplanned maintenance. Barrels per stream day reflect the maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude oil and product slate conditions with no allowance for downtime. Stream day capacity is typically about 6% higher than calendar day capacity. The Refinery Capacity Report also includes information about secondary units—downstream refinery units that are used to process the products coming from the atmospheric crude distillation unit into ultra-low sulfur diesel and gasoline, as well as other products. Secondary refining capacity, including thermal cracking (coking), catalytic hydrocracking, and hydrotreating and desulfurization, increased slightly, up 1% from year-ago levels. These downstream capacity increases are primarily the result of changing processes that can increase refinery throughput rather than building new refining units. The number of operating refineries decreased from 141 on January 1, 2017, to 135 on January 1, 2018, largely reflecting classification changes in EIA’s survey: four refineries previously considered separate in survey data were merged into two, and two refineries were reclassified from idle to shut down. Consequently, the decrease in number of operating refineries does not necessarily represent a meaningful change in U.S. refinery operating capacity. Record refinery runs have helped accommodate increases in U.S. crude oil production, which averaged 9.4 million barrels per day (b/d) in 2017, an increase of 4.0 million b/d from the level in 2009. Gross crude oil inputs to refineries averaged 16.6 million b/d in 2017 compared with 14.3 million b/d in 2009. Over that period, operable refinery crude distillation capacity increased 945,000 b/cd, and utilization rose from 83% in 2009 to 91% in 2017, resulting in the 2.3 million b/d increase in gross crude oil inputs. Over the same period, U.S. crude oil imports decreased by 1.1 million b/d, and U.S. crude oil exports increased by 1.1 million b/d. EIA’s Refinery Capacity Report also includes information on capacity expansions planned for the balance of the year. Based on information reported to EIA in the most recent update, U.S. refining capacity will not expand significantly during 2018. Further investment in U.S. refinery expansion projects depends on expectations about crude oil price spreads, the characteristics of the crudes being produced, product specifications, and the relative economic advantage of the U.S. refining fleet compared with refineries in the rest of the world.

U.S. exports of methyl tert-butyl ether (MTBE), a motor gasoline additive, totaled 38,000 barrels per day (b/d) in 2017, primarily to Mexico, Chile, and Venezuela. MTBE was once commonly used in the United States but was phased out in the late 2000s as a result of water contamination concerns. Since then, fuel ethanol has replaced MTBE as a gasoline additive. MTBE is a fuel oxygenate that boosts octane ratings and helps achieve more complete combustion in gasoline engines. Since 2005, most U.S. exports of MTBE have gone to Mexico and Venezuela, with increasing exports to Chile. In 2017, Mexico accounted for two-thirds (66%) of U.S. MTBE exports. Economic instability in Venezuela may have contributed to the decrease in U.S. exports of MTBE to that country in recent years. Overall, MTBE accounts for a small portion of total U.S. petroleum product exports, averaging 0.7% of the total in 2017. MTBE is used as an oxygenate instead of fuel ethanol in those countries, in part, because it has lower evaporative emissions, can be shipped in pipelines alongside finished petroleum products, and does not require the kinds of infrastructure investments specific to ethanol. Virtually all U.S. MTBE exports originate from the Gulf Coast, where production is concentrated. MTBE can be blended with motor gasoline blendstock in the United States to produce a finished product that is subsequently transported to destinations in Mexico. MTBE was once a common fuel additive in the United States. U.S. blending of MTBE into motor gasoline peaked in 1999 at 260,000 b/d. In that year, the volume of fuel ethanol added to motor gasoline totaled 38,000 b/d. However, between 2000 and 2007, 23 states instituted a partial or complete ban on MTBE blended into motor gasoline because of groundwater contamination concerns. The result was an eventual phase out as a fuel oxygenate in the United States and a decline in domestic MTBE consumption that was replaced with ethanol. In contrast to MTBE, the use of fuel ethanol has been supported by tax subsidies such as the Volumetric Ethanol Excise Tax Credit and by the Renewable Fuel Standard, which mandates the use of biofuels in the nation’s transportation supply. As a result, almost all motor gasoline in the United States contains 10% fuel ethanol blends. Principal contributors: Neil Agarwal, Steve Hanson