Koplak, 5 Cewek Cakep Ini Harus Terperangkap Gara-Gara Ulahnya Sendiri Bikin Kocak

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.

U.S. carbon dioxide (CO2) emissions from the transportation sector reached 1,893 million metric tons (MMmt) from October 2015 through September 2016, exceeding electric power sector CO2 emissions of 1,803 MMmt over the same time period. On a 12-month rolling total basis, electric power sector CO2 emissions are now regularly below transportation sector CO2 emissions for the first time since the late 1970s. CO2 emissions from electric power have been trending lower since 2007. Comparing emissions over a 12-month period reduces the effects of seasonal fluctuations. Both sectors tend to have higher consumption and emissions in the summer months when electricity demand and vehicle travel are relatively high. Emissions levels through September 2016 represent the latest available data in EIA’s Monthly Energy Review. The electric power sector makes up a larger share of total U.S. energy consumption than the transportation sector. However, CO2 emissions from the electric power sector are now lower than those from transportation because the carbon intensity of the power sector has fallen much faster than the carbon intensity of the transportation sector. Emissions from the electric power sector are primarily from coal-fired and natural gas-fired electric generators. On average, emissions associated with combusting coal are higher than those associated with combusting natural gas. The average rate of CO2 emitted from combusting coal ranges from 206 to 229 pounds per million British thermal units (lbs CO2/MMBtu), depending on the type of coal consumed. The combustion of natural gas emits on average 117 lbs CO2/MMBtu. Natural gas electric generators also tend to be more efficient than coal generators, because they require less fuel to generate electricity. In the 12 months from October 2015 through September 2016, coal and natural gas had nearly equal shares of electric power generation in the United States: 31% and 34%, respectively. However, their shares of electric power sector emissions were 61% and 31%, respectively, as coal is much more carbon-intensive. Overall electric power carbon intensity has also decreased as generation share of non-carbon-emitting fuels such as nuclear, hydropower, wind, and solar has grown. Emissions from the transportation sector are primarily from motor gasoline, distillate fuel oil, and jet fuel, which have carbon intensities lower than coal but higher than natural gas. For example, gasoline emits an average of 157 lbs of CO2/MMBtu. In the 12 months from October 2015 through September 2016, motor gasoline represented 60% of the total emissions from the transportation sector, while 23% was from distillate fuel oil and 12% was from jet fuel. Very little electricity is used in the transportation sector. Attributing transportation’s share of electric power sector emissions to the transportation sector would only add 4 MMmt CO2 to the transportation sector’s total of 1,893 from October 2015 through September 2016.

Spreads between the Columbia Gas Transmission Corp. Appalachian index (TCO Appalachia)—an actively traded location for both physical and financial transactions for natural gas in southwest Pennsylvania—and the Henry Hub in the U.S. Gulf Coast are changing due mainly to growth in Marcellus production. Natural gas at the TCO Appalachia index has historically been priced about $0.25 per million British thermal units (MMBtu) above Henry Hub. However, the spread between these two points in spot markets reflects rough parity now, and in forward markets TCO is priced less than at the Henry Hub. The natural gas price spread between TCO Appalachia and Henry Hub has been evolving. The monthly average spread, based on spot prices, ranged from $0.23-0.33/MMBtu during 2005-2008 and averaged $0.19/MMBtu in 2009, $0.15/MMBtu in 2010, and just $0.08/MMBtu in 2011. Through the first half of 2012, the TCO minus Henry Hub spread averaged just $0.02/MMBtu. In June 2012, spot gas priced at the TCO Appalachia index was lower than Henry Hub natural gas. As of early July, forward prices indicates that the TCO Appalachia basis swap is priced lower than the Henry Hub futures contract through the end of 2016, mostly reflecting the growth in Marcellus natural gas production. Rising production in the Marcellus basin is influencing the U.S. natural gas market in numerous ways, including: Changing Northeast price levels and differentials Reducing the need for Canadian natural gas imports Altering regional natural gas flow patterns Boosting requirements for more take-away pipeline capacity related to Marcellus production Expanding natural gas processing infrastructure needs Supporting increased use of natural gas for power generatorsDaily natural gas spot prices between Tennessee Gas Pipeline (TGP) Zone 4 Marcellus and Henry Hub have diverged recently largely due to rising Marcellus production, which has outpaced the growth of available take—away pipeline capacity in northern Pennsylvania. As a result, the spot price of natural gas at the TGP Zone 4 Marcellus trading point has fallen—at times considerably—below the spot price at Henry Hub in Louisiana, and is currently the least expensive wholesale natural gas in North America. To address this rapid growth in natural gas production, several Northeast interstate pipeline projects were completed in 2011, adding nearly 1.5 billion cubic feet per day (Bcf/d) of capacity in Pennsylvania. Many additional pipeline projects have been proposed or are in various stages of completion in the Northeast to reduce transportation constraints caused by growing Marcellus natural gas production. EIA's website has information on the status of some of these pipeline projects. Dry natural gas production in Pennsylvania, a key part of the Marcellus supply basin, continues to grow and according to Bentek Energy is now approaching 6 Bcf/d. Estimated June 2012 Marcellus dry natural gas production (5.7 Bcf/d) has nearly doubled since June 2011 (2.9 Bcf/d) and represents about 9% of overall U.S. dry natural gas production. Further, Bentek Energy estimates that there are over 1,000 natural gas wells that have been drilled in northern Pennsylvania but which are not yet producing natural gas because there is not enough interstate and gathering pipeline infrastructure to accommodate the new production.

In August 2017, total U.S. natural gas liquefaction capacity in the Lower 48 states increased to 2.8 billion cubic feet per day (Bcf/d) following the completion of the fourth liquefaction unit at the Sabine Pass liquefied natural gas (LNG) terminal in Louisiana. With increasing liquefaction capacity and utilization, U.S. LNG exports averaged 1.9 Bcf/d, and capacity utilization averaged 80% this year, based on data through November. Sabine Pass, located on the U.S. Gulf Coast near the Louisiana-Texas border, consists of four existing natural gas liquefaction units, or trains, with a fifth train currently under construction. When complete, Sabine Pass will have a total liquefaction capacity of 3.5 Bcf/d. Five additional LNG projects are currently under construction in the United States, and they are expected to increase total U.S. liquefaction capacity to 9.6 Bcf/d by the end of 2019: Cove Point liquefaction terminal (one train, 0.75 Bcf/d capacity) in Maryland is 97% complete, and Dominion Energy expects to place it in service before the end of 2017. Elba Island LNG (10 modular liquefaction trains, 0.03 Bcf/d capacity each) in Georgia is owned by Kinder Morgan. Six trains are scheduled to come online in the summer of 2018, and four trains are scheduled to come online by May 2019. Freeport LNG (three trains, 0.7 Bcf/d capacity each) in Texas is being developed by Freeport LNG Development, L.P. The first train is expected to come online in November 2018, with the remaining two trains following in six-month intervals. Corpus Christi (two trains, 0.6 Bcf/d capacity each) in Texas is being developed by Cheniere and is expected to come online in 2019. Cameron LNG (three trains, 0.6 Bcf/d capacity each) in Louisiana is being developed by Sempra LNG and is expected to come online in 2019. Overall utilization of existing LNG liquefaction facilities is expected to average 80% in 2017 and 79% in 2018, based on LNG export projections in EIA’s latest Short-Term Energy Outlook. Several factors can affect utilization rates, including weather-related disruptions, demand fluctuations, seasonality in import markets, production schedules for new LNG facilities, and maintenance on existing facilities. At Sabine Pass, the ramp-up process, combined with maintenance on Train 1, resulted in capacity utilization for Trains 1 and 2 averaging 51% in 2016. Capacity increased in 2017 with the addition of Trains 3 and 4, but the ramp-up periods for those trains, as well as lower spring demand in markets in Asia and Europe and disruptions caused by Hurricane Harvey in August, limited total utilization. Exports from Sabine Pass began to increase in September 2017 as Train 4 ramped up to full production—reaching 2.7 Bcf/d in November—with an overall capacity utilization rate of 96% across four trains. Utilization at Sabine Pass is projected to remain well above 90% in winter 2017–2018 as a result of expected strong natural gas winter demand and high spot LNG prices in Asia and Europe. Principal contributors: Victoria Zaretskaya, Kristen Tsai