Pria Ini Menunggu Menikahi Bocah Kecil, Penampakan Umur 17 Tahun Bikin Pangling

Escalating industry interest in the Utica Shale, which lies under the more familiar Marcellus shale and covers a wider geographic area, may boost Ohio into the ranks of U.S. States with significant increases in oil and natural gas production from horizontal drilling in shale formations. Although production volumes are still small, the number of Utica-targeted horizontal drilling permits issued to Ohio operators from January through September 2011 rose more than twenty-fold over full-year 2010. Ohio is not presently among the U.S. States experiencing significant oil and natural gas production increases from drilling in shale formations. Although the high-profile Marcellus Shale extends partially into Ohio, its more productive areas lie to the east, especially in Pennsylvania, where most of the exploration and development activity is centered. However, the underlying Utica Shale, which covers much of Ohio and parts of several other States from New York to Tennessee, offers considerable potential. In eastern Ohio, the Utica is thought to be relatively rich in oil and natural gas liquids that are currently worth significantly more than natural gas on an energy-equivalent basis. Preliminary estimates by Ohio's Department of Natural Resources (ODNR) suggest a recoverable reserve potential of between 1.3 and 5.5 billion barrels of oil as well as 3.8 to 15.7 trillion cubic feet of natural gas. Industry interest in the Utica is already apparent: from January through September 2011, ODNR issued a total of 42 permits for drilling horizontal wells in Ohio's portion of the Utica Shale. In sharp contrast, only 2 such permits were issued in all of 2010. Recent major acreage acquisitions also underscore the industry's budding interest in Ohio's slice of the Utica. In September, Hess Corporation announced its $750 million acquisition of Marquette Exploration LLC, which included a 100% interest in 85,000 acres. The Marquette purchase fell closely on the heels of another deal in which Hess paid $593 million to CONSOL Energy for a 50% stake in about 200,000 acres. Hess' deals follow a series of transactions though which Chesapeake Energy amassed 1.25 million acres at a reported cost of between $1.5 billion and $2 billion. Ohio's oil and natural gas production has been fairly flat in recent years, with annual production averaging about 5.5 million barrels and 89.0 billion cubic feet, respectively, over the last ten years (see chart). The extent to which the Utica Shale will contribute to Ohio's oil and natural gas production remains to be seen. Shale-focused exploration and development in some States has significantly boosted production. North Dakota, for example, has become the Nation's fourth largest oil-producing State, due in large part to horizontal drilling in its portion of the Bakken Shale formation. Similarly, Pennsylvania's natural gas production has grown substantially with accelerating horizontal drilling in the Marcellus. According to the Pennsylvania Department of Environmental Protection, total natural gas production in 2009 was about 288 billion cubic feet (Bcf). In the first half of 2011, natural gas production from the Pennsylvania portion of the Marcellus alone was about 435 Bcf, with full-year production likely to approach one trillion cubic feet.

While hurricanes in 2005 and 2008 had extensive and long-lasting impacts on oil and natural gas production in the Gulf of Mexico (GOM) and refining activity along the Gulf Coast, the temporary disruption of production experienced during Tropical Storm Lee is more typical of the impact with hurricane season storms that do not significantly damage energy infrastructure. Evacuation of personnel from platforms and rigs began on September 1 in anticipation of approaching Tropical Storm Lee. The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) reported that a cumulative total of nearly 5 million barrels of crude oil and over 13 billion cubic feet (Bcf) of natural gas production had been shut in through Friday, September 9 and that shut-ins peaked on September 3, when 60.3% of crude oil and 54.6% of natural gas production from platforms and rigs in the GOM were off-line. Crude oil production in the Federal Gulf of Mexico region is typically about 1.5 million barrels per day, and represents about 27% of total domestic crude oil production. Production shut downs and recovery at these platforms and rigs take several days. So, although the storm crossed through the region over the weekend of September 3-4, some rigs and platforms were closed down before and after the storm moved through the area. For the 2011 hurricane season, BOEMRE assumed GOM maximum daily production rates of 1.4 million barrels of crude and 5.3 Bcf of natural gas when the region is unaffected by weather or other disruptions. The GOM hurricane season typically runs from June through November. Tropical Storm Lee was not the first summer storm in the region. Tropical Storm Don was active at the end of July, taking over 500,000 barrels of crude and 1.1 billion cubic feet of natural gas offline. Total cumulative GOM production losses for oil and natural gas so far this year due to storms are similar to the relatively low levels in 2009 and 2010. The 2005 hurricane season resulted in record oil and natural gas production outages in the GOM. A total of 12 hurricanes passed through the area contributing to production shut-ins. Hurricanes Katrina and Rita, both category 5 hurricanes, caused a combined total of over 100 million barrels of crude and more than 500 Bcf of natural gas shut-ins. Both of these outages persisted for several weeks and included many days of no production. The 2008 outage levels rank second to the outages experienced in 2005. In 2008, Hurricanes Ike and Gustav, both category 4 storms, shut in nearly 60 million barrels of crude oil and 350 Bcf of natural gas production.

Libya, the largest holder of proven oil reserves in Africa and until recently its fourth largest oil producer, exports most of the energy it produces. Europe is the major market for both oil and natural gas exports from Libya. Following the outbreak of civil unrest in mid-February, Libyan oil and natural gas production has been cut by 60 to 90 percent, affecting Libya's energy exports. Oil exports have fallen with production and Libya's natural gas exports to Italy via the Greenstream pipeline stopped in late February. Libya produced an estimated 1.8 million barrels per day (bbl/d) of oil in 2010, of which 1.5 million bbl/d were exported. Libya exports nine grades of crude oil. API gravities range from 26.0 degrees to 43.3 degrees, with a sulfur content as low as 0.2-0.3%. While the lighter, sweeter grades are generally sold to Europe, the heavier crude oils are often exported to Asian markets. About 85% of Libyan oil exports go to Europe, including Italy, Germany, France, and Spain. Italy is the top destination for Libyan oil, which accounted for 28% (376,000 bbl/d) of Italy's total oil imports in 2010. The United States imported an average of 70,500 bbl/d from Libya in 2010, or 0.6% of our total imports (according to EIA January through December estimates). About 3% (150,000 bbl/d) of China's oil imports came from Libya in 2010. Libyan natural gas exports Libya produced an estimated 562 billion cubic feet (Bcf) of dry natural gas in 2009, one third of which is domestically consumed. Libya exports the remainder of its natural gas. Libya became a liquefied natural gas (LNG) exporter in 1971, the second country in the world to export LNG after Algeria. Natural gas exports to Europe have grown considerably since 2004 through the 370-mile underwater Greenstream natural gas pipeline that runs from Melitah, Libya to Gela, Sicily. From Sicily, the natural gas flows to the Italian mainland. All Libyan natural gas exports go to Europe. In 2009, Libya exported 349 Bcf, the vast majority by pipeline, with a small volume exported in the form of LNG. Libyan natural gas accounted for 13% of total Italian gas imports in the first 11 months of 2010, the top destination country, according to the International Energy Agency. See EIA's Libya Country Analysis Brief for more information about Lib

Roughly 70% of petroleum-fired electric generating capacity that still exists today was constructed prior to 1980. Utility-scale generators that reported petroleum as their primary fuel comprised only 3% of total electric generating capacity at the end of 2016 and produced less than 1% of total electricity generation during 2016. Power plants that burn petroleum liquids (such as distillate or residual fuel oils) are generally used for short periods during times of peak electricity demand. Otherwise, petroleum-fired power plants operate mostly at low capacity factors because of the high price of petroleum relative to other fuels, air pollution restrictions, and lower efficiencies of their aging generating technology. Most oil-fired generators are either turbines or internal combustion engines used to supply power only at times of peak electric power demand or when natural gas prices rise due to local natural gas demand. A fundamental shift in the perception of oil as a utility fuel occurred during the 1970s when world oil markets experienced sharp price increases. Supply shortages during world events such as the Arab Oil Embargo, the Iranian Revolution, and the Iran-Iraq war also discouraged petroleum-fired electricity generating capacity additions in the United States. Of the 36.4 gigawatts of domestic petroleum-fired generating capacity, more than 68% is located in 10 states, primarily in coastal states with access to marine ports. When these plants were built in the 1970s, coal-fired generators were the main sources of electricity generation. However, coastal states like Florida are relatively far from coal production areas. Because coal is primarily transported by rail, the cost of long-haul coal transport by rail may not be competitive in these areas compared with oil delivered by marine modes. In recent years, monthly generation from petroleum-fired generators has totaled 1 million to 2 million megawatthours. However, in both January 2014 and January 2015, petroleum-fired generation spiked when cold winters in New England created high demand for the region’s natural gas supply and petroleum generators were needed to meet load. Because oil-fired generators tend to be used to meet electricity demand for times of peak demand, oil-fired generators generally have lower capacity factors and higher heat rates than most other types of power plants. Capacity factors—which measure actual output as a percent of total capacity—for oil-fired steam turbines are about 10% and approach 20% only in the summer months. Capacity factors for oil-fired combustion turbines and internal combustion engines are lower, remaining well below 5%. Some power plants are capable of switching between fuels, potentially complicating the calculation of capacity factors. For instance, plants that normally burn natural gas may choose to burn petroleum during times of high natural gas demand. EIA calculates capacity factors based on the primary fuel of each power plant, so the consumption of petroleum fuels in plants that primarily consume natural gas would be reflected in petroleum’s net generation but may not be reflected in the petroleum capacity factor series.

The United States is expected to become a net exporter of natural gas on an average annual basis by 2018, according to the recently released Annual Energy Outlook 2017 (AEO2017) Reference case. The transition to net exporter is driven by declining pipeline imports, growing pipeline exports, and increasing exports of liquefied natural gas (LNG). In most AEO2017 cases, the United States is also projected to become a net exporter of total energy in the 2020s in large part because of increasing natural gas exports. In 2016, the United States was a net importer of natural gas, with net imports of 0.9 trillion cubic feet (Tcf), or 2.6 billion cubic feet per day (Bcf/d). As several LNG export projects currently under construction are completed, LNG exports are expected to make up a growing share of natural gas exports and to surpass pipeline exports of natural gas by 2020. The Sabine Pass facility in Louisiana became the first operating LNG export facility in the Lower 48 states in 2016. By 2021, four LNG export facilities currently under construction are expected to be completed. Combined, these five plants are expected to have an operational export capacity of 9.2 billion cubic feet per day. After 2021, projected U.S. exports of LNG grow at a more modest rate as U.S. natural gas faces growing competition from other global LNG suppliers. U.S. exports of natural gas by pipeline to Mexico are also expected to increase. U.S. exports to Mexico have doubled since 2009 and are projected to continue rising through at least 2020 as pipeline projects currently under construction are completed. U.S. imports of natural gas, most of which come by pipeline from western Canada, are projected to continue declining. In addition to importing less natural gas from Canada, primarily from Alberta, increasing amounts of natural gas from the Marcellus and Utica basins in the Northeast and Midwest regions of the United States are expected to flow to eastern Canadian provinces. Despite these trends, the United States is expected to remain a net importer of natural gas by pipeline from Canada through 2040 in all but one case in the AEO2017 analysis. In the High Oil and Gas Resource and Technology case, higher natural gas production leads to greater exports of natural gas, and the United States becomes a net exporter of natural gas by pipeline to Canada by 2030. The growth of natural gas exports, especially from new LNG terminals, sustains continued growth in U.S. natural gas production. In the Reference case, natural gas production is projected to grow through 2020 at about the same rate (3.6% annual average) as it has since 2005, when production of natural gas from shale formations began to grow rapidly. After 2020, natural gas production grows at a lower rate (1.0% annual average) in the Reference case as net export growth moderates, energy efficiencies increase, and natural gas prices slowly rise. Natural gas production and trade vary with different assumptions for resources and technology, macroeconomic growth, and world oil prices. In the High Oil and Gas Resource and Technology case, larger natural gas resource estimates and improved drilling technology lead to higher domestic natural gas production, lower U.S. natural gas prices, and therefore, greater natural gas exports. Most of the increase in natural gas trade is from LNG exports, which grow to 8.4 Tcf (23 Bcf/d) in 2040. However, LNG exports are highest in a case with high world oil prices. In the High Oil Price case, when consumers move away from petroleum products when other energy sources become economically favorable, global LNG demand increases and U.S. LNG exports reach 9.2 Tcf, or 25 Bcf/d. Compared with other LNG suppliers, U.S. LNG has the advantage of domestic spot prices that are less sensitive to global oil prices. Conversely, in a scenario with more pessimistic assumptions for oil and gas resources and technology or a scenario with low world oil prices, LNG exports still increase, but remain below Reference case levels through 2040.