Viral Gadis Cantik Penjual Popcorn, Kisahnya Tak Seperti yang Dibayangkan

The January 2012 outage at the San Onofre Nuclear Generating Station (SONGS), located just north of San Diego, changed the California electricity market. SONGS Units 2 and 3 provided the market with a consistent source of baseload electricity since the units began operating in 1983 and 1984 (Unit 1, which began operating in 1967, permanently shut down in 1992). The loss of SONGS is a significant contributor to changes in the California electricity generating profile over the past year. The SONGS facility is composed of two pressurized water nuclear reactors that together have a rated net summer capacity of 2,150 megawatts (electric). Nuclear power plants such as SONGS are important sources of baseload electricity because of their high output capability and low variable operating costs. SONGS played an important role in the electricity generation profile of the region as a result of its high output and location in the electric demand center of Southern California. Between 2002 and 2011, SONGS generated an average of 16,218,635 megawatt hours of electricity each year. This generation represented 18% of the total electricity generation in the Southern California Edison and San Diego Gas and Electric California ISO zones during this period. The units operated at full capacity during the summer, when demand was highest; output was lowest when either of the units underwent a refueling outage. Both units went offline this January and remain shut down, creating challenges for the Southern California electric grid. Electricity demand between 2011 and 2012 remained essentially unchanged, leaving California utilities to deliver the same amount of electricity to customers without one of the largest in-state suppliers. In addition to the loss of generation by SONGS, in-state hydroelectric power generation was lower through July of this year. Increases in generation at natural gas-fired power plants in the state offset the reduced nuclear and hydro generation. Natural gas generation was up through July 2012 by 24% when compared to the same period of 2011. Lower natural gas prices, in general, have moderated the increase in operating costs caused by using natural gas instead of nuclear generation in California so far in 2012. Average on-peak power prices in Southern California in 2012 so far are lower than in 2011, despite increased natural gas demand. The average on-peak wholesale price of electricity in Southern California through July 2012 was $30/MWh, down from $37/MWh during the same period in 2011. On the other hand, the average off-peak wholesale power price during this same period in 2012 was $21/MWh, up slightly from last year's price of $19/MWh. This was due to natural gas replacing nuclear power as the marginal fuel in Southern California during off-peak hours. The variable operating costs of nuclear power are very low, and it is often the marginal fuel during periods of low demand. The reduction of available in-state supply resulted in California importing more electricity. Electricity imports through July 2012 were approximately 90 percent higher than in the first half of 2011. California historically imported significant amounts of electricity, since its wholesale power markets in the region are relatively open and generation from outside the state is often less expensive. Some power plants located in adjacent states are partially owned by California utility companies, and special agreements exist for exporting power to California. For instance, 18% of the Palo Verde Nuclear Power Plant, located in Tonopah, Arizona, is owned by California-based utilities. Outages at the SONGS nuclear plant have also affected the natural gas market. According to Bentek Energy, natural gas demand by Southern California Natural Gas—a local distribution company providing retail natural gas service to Southern California—was up 262 million cubic feet per day, or 10%, so far in 2012 (Jan. 1-Nov. 8) compared to the same period in 2011. To meet higher demands, flows on interstate natural gas pipelines such as El Paso Natural Gas and Transwestern delivered more natural gas into Southern California. Because of these increased natural gas deliveries, the spreads between the price of natural gas at Henry Hub and key price benchmarks in California—the SoCal Citygate and the PG&E Citygates trading points—rose on average about $0.16-$0.20/MMBtu (Jan. 1-Nov. 8), even while average spot gas prices went down. Further, the premium between natural gas priced at the PG&E and the SoCal Citygate trading points fell on average to $0.09/MMBtu in 2012 (Jan 1-Nov 8) compared to the same period in 2011.

The wind energy production tax credit (PTC), along with state-level policies, has boosted the growth of the U.S. wind industry over the past decade, but the PTC is set to expire at year-end unless legislation extending its provisions is approved. This tax credit was first implemented in 1992, when the United States had less than 1.5 gigawatts (GW) of installed wind capacity. By the end of 2011, wind capacity stood at more than 45 GW, about 4% of U.S. power generating capacity, and provided 3% of total U.S. electricity generation in 2011. Wind's generation share is below its capacity share because wind's capacity utilization is limited to windy periods. Data reported to EIA for 2012 point to another year of significant wind capacity additions, following a trend of increasing capacity additions in anticipation of a PTC expiration. Since its implementation in 1992, the PTC has significantly contributed to wind development in the United States by increasing the financial return on a wind energy investment and allowing wind plants to price their generation more competitively. The cycle of expirations and reauthorizations of the wind PTC (see red labels in chart) during the past decade has had a noticeable effect on wind development through its impact on the planning and financing of wind energy projects. The PTC was first enacted as part of the 1992 Energy Policy Act as a replacement for prior incentives for wind generation under the Public Utility Regulatory Policies Act of 1978 and an investment tax credit (ITC) first made available under the Energy Tax Act of 1978. The PTC is a credit based on annual production of electricity from eligible resources. The initial tax credit of 1.5 cents per kilowatthour (1992 dollars) for the first 10 years of output from plants entering service by December 31, 1999, included an annual adjustment for inflation and is currently valued at 2.2 cents per kilowatthour (2011 dollars). Although amendments to the original law have expanded it to a wide variety of renewable resources and technologies, the original PTC applied to generation from tax-paying owners of new wind plants, as well as eligible biomass power plants. In its early years, the PTC had little discernible effect on the industries it was designed to support. By 1999, when the provision was originally set to expire, U.S. wind capacity had begun growing again, and the PTC supported the development of more than 500 megawatts of new wind capacity in California, Iowa, Minnesota, and other states that had implemented policies to support or require renewable generation capacity. State-level programs encouraged wind power development. For example, the mandate in Minnesota for 425 megawatts of wind power by 2003 was part of a settlement with Northern States Power (now Xcel Energy) to extend on-site storage of nuclear waste at its nuclear facility. In 1999, Texas became the first state to implement a renewable portfolio standard (RPS) for a competitive electricity supply market. Cycles of expiration and reauthorization. From 1999 to 2004, Congress allowed the PTC to expire three times, each time retroactively extending it several months after the expiration deadline had passed. The two-year cycle of expiration and re-extension is apparent (see chart, starting in 1999). In the 12-month period immediately prior to the expiration dates (which, after 1999, were always pegged to the last day of the calendar year), new installations reached high levels as developers rushed to beat the legislative deadline, followed by a substantial retrenchment in the following year as the status of the tax credit was sorted out. Congress has not allowed the PTC to expire since passage of the Working Families Tax Relief Act of 2004. In the period from 2005 to 2010, the wind industry experienced a period of consistent year-over-year growth. This growth occurred as the number of states with renewable power requirements increased. Recession and recovery. The break in this growth streak occurred in 2010, as an echo effect of the financial crisis and recession from late 2008 and 2009. While wind projects were still eligible for tax credits, a lack of investors with sufficient tax appetite, or tax-situation ability to take advantage of the credits, a general decline in the need for new sources of generation, and a decline in natural gas prices that hurt the competitiveness of wind on a cost basis all contributed to slower growth for wind capacity in 2010. In 2009, as part of the American Recovery and Reinvestment Act (ARRA), Congress modified the PTC to address the tax appetite issue. In particular, the ITC was reintroduced for wind and other PTC-eligible technologies at a 30% level. In addition, projects starting construction before the end of 2011 may elect to receive an equivalent-value cash grant in lieu of the ITC (known as a 1603 Grant after its ARRA section number), thus mitigating the need for investors with sufficient tax burdens to be offset by the ITC. Recent events. In 2011, wind power construction began to rebound from the 2010 retrenchment, largely with projects taking advantage of the 1603 Grant before its expiration. The trend has continued through 2012, with approximately 6 GW of new installations through October and another 6 GW expected to enter service in the last months of the year, as reported to EIA by project developers. If all reported capacity installations are completed as reported to EIA, 2012 would again set a record for new wind installations in the United States. In 2011, installed wind capacity stood at more than 45 GW, and generated almost 120 million megawatthours of electricity, accounting for about 4% of U.S. installed capacity and 3% of total U.S. generation in 2011. Currently, the PTC is scheduled to expire for new wind generators entering service after the end of 2012. Other PTC-eligible technologies may continue to receive this tax credit for facilities that begin operation during 2013. Eligibility of these projects for the ITC will expire at the same time as eligibility for the PTC (end of 2012 for wind, end of 2013 for other PTC-eligible technologies). Projects that were under construction before the end of 2011 will still be eligible for a 1603 Grant, as long as they enter service prior to expiration of the PTC or ITC for their technology class.

The January 2012 outage at the San Onofre Nuclear Generating Station (SONGS), located just north of San Diego, changed the California electricity market. SONGS Units 2 and 3 provided the market with a consistent source of baseload electricity since the units began operating in 1983 and 1984 (Unit 1, which began operating in 1967, permanently shut down in 1992). The loss of SONGS is a significant contributor to changes in the California electricity generating profile over the past year. The SONGS facility is composed of two pressurized water nuclear reactors that together have a rated net summer capacity of 2,150 megawatts (electric). Nuclear power plants such as SONGS are important sources of baseload electricity because of their high output capability and low variable operating costs. SONGS played an important role in the electricity generation profile of the region as a result of its high output and location in the electric demand center of Southern California. Between 2002 and 2011, SONGS generated an average of 16,218,635 megawatt hours of electricity each year. This generation represented 18% of the total electricity generation in the Southern California Edison and San Diego Gas and Electric California ISO zones during this period. The units operated at full capacity during the summer, when demand was highest; output was lowest when either of the units underwent a refueling outage. Both units went offline this January and remain shut down, creating challenges for the Southern California electric grid. Electricity demand between 2011 and 2012 remained essentially unchanged, leaving California utilities to deliver the same amount of electricity to customers without one of the largest in-state suppliers. In addition to the loss of generation by SONGS, in-state hydroelectric power generation was lower through July of this year. Increases in generation at natural gas-fired power plants in the state offset the reduced nuclear and hydro generation. Natural gas generation was up through July 2012 by 24% when compared to the same period of 2011. Lower natural gas prices, in general, have moderated the increase in operating costs caused by using natural gas instead of nuclear generation in California so far in 2012. Average on-peak power prices in Southern California in 2012 so far are lower than in 2011, despite increased natural gas demand. The average on-peak wholesale price of electricity in Southern California through July 2012 was $30/MWh, down from $37/MWh during the same period in 2011. On the other hand, the average off-peak wholesale power price during this same period in 2012 was $21/MWh, up slightly from last year's price of $19/MWh. This was due to natural gas replacing nuclear power as the marginal fuel in Southern California during off-peak hours. The variable operating costs of nuclear power are very low, and it is often the marginal fuel during periods of low demand. The reduction of available in-state supply resulted in California importing more electricity. Electricity imports through July 2012 were approximately 90 percent higher than in the first half of 2011. California historically imported significant amounts of electricity, since its wholesale power markets in the region are relatively open and generation from outside the state is often less expensive. Some power plants located in adjacent states are partially owned by California utility companies, and special agreements exist for exporting power to California. For instance, 18% of the Palo Verde Nuclear Power Plant, located in Tonopah, Arizona, is owned by California-based utilities. Outages at the SONGS nuclear plant have also affected the natural gas market. According to Bentek Energy, natural gas demand by Southern California Natural Gas—a local distribution company providing retail natural gas service to Southern California—was up 262 million cubic feet per day, or 10%, so far in 2012 (Jan. 1-Nov. 8) compared to the same period in 2011. To meet higher demands, flows on interstate natural gas pipelines such as El Paso Natural Gas and Transwestern delivered more natural gas into Southern California. Because of these increased natural gas deliveries, the spreads between the price of natural gas at Henry Hub and key price benchmarks in California—the SoCal Citygate and the PG&E Citygates trading points—rose on average about $0.16-$0.20/MMBtu (Jan. 1-Nov. 8), even while average spot gas prices went down. Further, the premium between natural gas priced at the PG&E and the SoCal Citygate trading points fell on average to $0.09/MMBtu in 2012 (Jan 1-Nov 8) compared to the same period in 2011.

Despite causing more than eight million customers to lose power, Hurricane Sandy had only a small effect on wholesale electricity markets. Disruptions to electricity demand in the wake of the storm partially offset the temporary loss of supply, limiting wholesale price increases. Although supply and demand imbalances can result in significant price effects, power markets remained relatively orderly despite the stress from the storm. This was shown by the continued operation of the regional transmission organizations, which manage the transmission grid and the wholesale electricity markets across the Northeast. Demand for electricity in PJM, ISO-New England and the New York ISO (the regional transmission organizations that serve the Mid-Atlantic and Northeastern regions) fell 18%, 5%, and 17%, respectively, between October 29 and 30, after Hurricane Sandy made landfall on October 29. This was largely due to extensive retail customer outages in the region; however, trading in the wholesale electricity markets continued throughout the disruption. Short-term spikes in the real-time electricity markets similar to previous supply disruptions occurred, however the day-ahead prices remained relatively stable. The immediate drop in real-time prices (see chart above) in New York ISO after Sandy made landfall indicate oversupply on the system. Short-term spikes in electricity hubs in Western New York occurred at peak load the next day as generation sources in New York City and other eastern portions of the system remained offline, increasing demand from sources in the west. Real-time prices in ISO-New England were stable in the days after Hurricane Sandy's landfall. In PJM, real-time markets operated though the RTO did declare a Minimum Generation Event, a signal that the dispatcher could not match decreasing load and emergency reducible generation was necessary. Overall the bulk-transmission system continued to operate, despite loss of some transmission lines and substations. Day-ahead, on-peak power prices in the region continued to range between $30 and $55 per megawatthour in the days after the storm. Recent cold weather has increased day-ahead prices across the Northeast above levels seen after the landfall of Hurricane Sandy. Several nuclear power plants were shut down or reduced output due to damage to transmission lines, concerns over storm surge, and other severe-weather precautions. Substations and other key electricity supply infrastructure were also damaged in the storm.

Hurricane Sandy caused a massive power outage in the Northeast. According to the Department of Energy's Office of Electricity Reliability and Delivery, about 8.5 million customers (residential, commercial, and industrial) were without power at some point during or after the storm, mostly in parts of the Mid-Atlantic, Northeast, and the Ohio Valley. On 10/30/12, the day after Hurricane Sandy made landfall, 8.2 million customers were without power. For New Jersey, it was the largest power outage in the history of the state. The recovery efforts have been slowed by flood damage and recent snowfall. As of 11/08/12, power has been restored to around 90% of the customers who experienced an outage, but it is unclear how long it will take to fully restore service. In many areas, structures will need to be repaired or rebuilt before service is restored. High snowfall in recent days has also slowed the recovery efforts in many Northeastern states. Disruptions from Hurricane Sandy exceeded both in magnitude and duration those from Hurricane Irene, which affected millions of Northeastern customers in late August and early September 2011. The customer outage counts provided by utilities and charted above count the number of meters without service, and not the number of people affected. One meter might represent a single-family home with 4 people, a small apartment building with 150 people, or a commercial building like a gas station, where a power outage could affect many people. Utilities will likely incur very large labor and equipment costs to restore electric service. Most of these costs will be passed on to retail consumers through higher electricity rates, but price increases could occur over a year or more as state commissions assess the costs through various regulatory processes. Storm-related power outages sometimes raise questions about burying power lines. However, the flooding caused by Hurricane Sandy, especially in the New York City area (where most of the lines are underground), demonstrated that underground transmission and distribution infrastructure are not necessarily immune to damage. Homes built since about 1970 use electricity and natural gas as their main space heating fuel in roughly equal proportions, a stark contrast to homes built before 1970, when natural gas dominated heating fuel choice. Other fuels such as fuel oil, liquefied petroleum gases (propane), wood, and kerosene are more likely to be used as heating fuels in homes built before 1970. The choice of fuel used for primary space heating also tends to drive fuel choice for water heating, cooking, and clothes drying. Virtually all other residential end uses are powered by electricity alone. Households' heating fuel choice is part of the most recent Residential Energy Consumption Survey (RECS) data characterizing how households were using energy in 2009. A household's choice of heating fuel is dependent on several factors such as who makes the decision and what fuels they can choose from. The residents of the house may not have made the choice—often primary heating fuel and equipment is decided by the builder or contractor. Over time, households can switch heating equipment, which sometimes results in switching fuels as well. And certain fuels are not available in some areas of the country. Fuel choice tends to vary significantly by region. Part of the change over time is explained by population shifts toward warmer and drier climates in the South and West regions. The fastest-growing region, the South, is primarily heated by electricity. The Midwest and West are mostly heated by natural gas. Fuel oil is generally only used in the Northeast; less than two percent of homes outside the Northeast use fuel oil (also known as distillate oil) as their primary space heating fuel. Over 99% of homes make some use of electricity, but no other fuel is nearly as widespread. RECS data show how often fuels are used in households for any purpose, not just space heating. About 61% of homes use natural gas, followed by propane (43%), wood (12%), and fuel oil (7%). All remaining fuels are used in only one percent of homes. Relatively few uses (including space heating, water heating, cooking, and clothes drying) offer a choice of equipment across fuels. Almost everything else including air conditioners, lights, refrigerators, televisions, computers, electronics and other devices is powered only by electricity. RECS provides data on how several residential energy characteristics can vary, presenting data by Census region, Census division, for selected states, year of construction, type of household, climate region, owned or rented, urban or rural, number of household members, and household income.

A combination of natural gas prices at 10-year lows and the warmest winter on record led to lower on-peak wholesale electricity prices so far in 2012. On-peak prices fell between 24% and 39% across major wholesale price hubs from January to June of 2012 compared to the same period of 2011 (see map above). Off-peak (nights and weekends) electricity prices were also down for first-half 2012 compared to first-half 2011, although generally less than the declines in on-peak prices over that period (see map below). In contrast to other major power trading locations, off-peak prices in Northern California at CAISO NP15 increased 10% when compared to first-half 2011, mainly because of more nuclear outages this spring and record-breaking hydroelectric output during the spring of 2011. Off-peak prices generally reflect the cost of maintaining output from baseload generators, while on-peak prices reflect the price of generating from intermediate and peak generators throughout a given day. Spot natural gas prices during the first half of 2012 generally fell about 40-50% compared to the same period in 2011 and on some days neared their lowest levels in a decade. Lower natural gas prices led to increasing use of natural gas to generate electricity, contributing to lower wholesale electricity prices, especially for on-peak prices. In 2012, twenty-eight states, mainly in the middle and eastern portions of the United States, reported their highest average daily temperatures for first half of any year during the past 118 years according to information reported by the National Oceanic and Atmospheric Administration (see map below). Warm weather at the start of 2012 contributed to reduced demand for both electricity and natural gas to heat homes, and contributed to lower wholesale natural gas and electricity prices. Average spot natural gas prices in key regional markets, which reflect the wholesale price of natural gas at major trading points, declined about 38% to 49% during the first half (January 1 to June 30) of 2012 compared to the same period in 2011. Natural gas spot prices at the Henry Hub—a key benchmark and major trading location—averaged about $2.36 per million British thermal units (MMBtu) during the first half of 2012. Rising production, record end-of-winter storage inventories, and mild weather contributed to spot natural gas prices nearing their lowest levels in a decade until prices rebounded at most trading points to the high $2/MMBtu range by the end of June. Specific factors contributing to lower average spot natural gas prices during the first half of 2012 include: Supply: U.S. dry natural gas production was about 5% higher during the first half of 2012 compared to the same period in 2011, according to Bentek Energy. This growth has been largely driven by gains in the Marcellus shale, where production nearly doubled from June 2011 to June 2012 and now comprises about 9% of total U.S. dry gas production. Increases in the Marcellus basin helped offset: slower growth or even modest declines in other gas supply areas, lower deliveries of liquefied natural gas (LNG), reduced net imports (imports minus exports) via pipelines from Canada, and increased natural gas exports to Mexico. Results through the first half of 2012 underscore the United States' declining dependence on imported natural gas. Consumption: Overall natural gas consumption was up just over 1% through the first half of this year, so U.S. natural gas supply rose faster than consumption. However, consumption by sector varied. Residential and commercial sector natural gas consumption was down 16% in the first half of 2012 because the mild winter reduced space heating needs. For example, U.S. population-weighted heating degree days were lower than normal in January (-18%), February (-13%) and March (-36%). But this decline in demand for heating was more than offset by demand from the power sector, where sustained low natural gas prices have resulted in a shift towards more natural gas-fired electric generation and demand was up 25% from the first half of 2011. Storage: The U.S. Lower 48 states had record natural gas storage inventories at the close of the winter 2011/2012 (November 2011 through March 2012). As a result, storage operators or their customers have not needed to buy as much natural gas to inject in preparation for the upcoming winter or to manage day-to-day imbalances, and this has contributed to lower natural gas prices. Last month, total U.S. natural gas storage inventories in the Lower 48 states topped three trillion cubic feet for the first time ever during June. As of August 3, storage inventories were 14% above the five-year average. The August 2012 Short-Term Energy Outlook forecasts that inventories by the end of October will exceed 3.9 trillion cubic feet, a record high.