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Natural gas inventories end heating season above five-year average Working natural gas in storage as of March 31, the traditional end of the heating season, totaled 2,051 billion cubic feet (Bcf), or almost 15% above the five-year average according to EIA's Weekly Natural Gas Storage Report. The total inventory of U.S. natural gas in storage tends to follow seasonal patterns of injections through the summer and withdrawals during the winter. Unlike the 2015–2016 heating season’s extremely high levels of natural gas inventories due to mild weather, inventories during the 2016–2017 heating season closely tracked the five-year average (2012-2016) until withdrawals slowed toward the end of the season. At the end of March 2016, U.S. natural gas storage inventories were near the highest on record for the end of a heating season, totaling 2,470 Bcf, or 54% higher than the previous five-year average (2011-2015). For most of 2016 and continuing into the 2016–2017 heating season, inventories remained above the previous five-year average. Inventories began the most recent heating season at a record of 4,047 Bcf on November 11, 2016, because of relatively warm seasonal weather. Overall natural gas consumption during the 2016–2017 heating season was about the same as the previous year, but U.S. dry natural gas production fell by 3% over that same period. Natural gas consumption in the residential, commercial, and industrial sectors remained relatively unchanged. Responding to slightly higher natural gas prices, natural gas consumed in U.S. electric power generation fell 2.1 Bcf from the 2015–2016 heating season, but the drop was almost entirely offset by a 2.0 Bcf increase in natural gas exports from the United States, according to data from PointLogic. EIA’s latest Short-Term Energy Outlook expects an increase in working natural gas inventories of about 1,750 Bcf through this summer’s injection season. The resulting forecast of U.S. natural gas inventories at the end of October 2017 suggests that they will not match the record high end-of-injection-period levels set at the end of October 2016. Similar to recent consumption patterns, consumption in the residential, commercial, and industrial sectors is expected to remain relatively flat on an annual average basis as electric power sector consumption of natural gas declines slightly and gross natural gas exports—especially liquefied natural gas exports—continue to increase. Principal contributors: Kristen Tsai, Owen Comstock

Despite its estimated 802 trillion cubic feet (Tcf) of unproved, technically recoverable shale gas resources, Argentina’s dry natural gas production declined each year from 2006 to 2014, and the country has shifted from a net exporter of natural gas to a net importer. In 2015, natural gas production increased for the first time since 2006, as ongoing efforts to increase production from key shale gas areas in Argentina aimed to reduce its imports of natural gas. Once one of the largest natural gas exporters in South America, Argentina was a net importer of natural gas by 2008. Imports, which accounted for 23% of Argentina’s natural gas consumption in 2015, came by pipeline from countries such as Bolivia and, to a lesser extent, as liquefied natural gas (LNG) from sources such as Trinidad and Tobago. The Argentinian government hopes to stop importing LNG by 2022. Argentina is the third country in the world, after the United States and Canada, to commercially develop tight oil and shale gas. Argentina’s Vaca Muerta formation within the Neuquen Basin has an estimated 308 Tcf of technically recoverable shale gas resources. Vaca Muerta’s geologic properties have been compared to the Eagle Ford play near the Gulf of Mexico in Texas in terms of its depth, thickness, pressure, and mineral composition. More than 588 vertical and horizontal shale wells have been drilled and completed in the Vaca Muerta shale play since 2010. According to the Argentine Ministry of Energy and Mines, shale gas production reached 64.6 billion cubic feet (Bcf) at the end of 2015. Argentina's national oil company, Yacimientos Petroleiferos Fiscales (YPF), the most active operator in the Vaca Muerta shale play, has initiated joint venture pilot project agreements with partners such as Chevron, Dow Chemical, and Petronas to further develop the play. Although Vaca Muerta may have similar geologic properties to the Eagle Ford play in the United States, the production history of the Eagle Ford may be difficult to replicate in Argentina. From 2010 to 2013, more than 10,000 wells were drilled in the Eagle Ford, and average inital production per well nearly tripled over that period. However, since 2014, the decline in world oil prices has resulted in lower upstream capital expenditures as operators prioritize their spending. While drilling costs in Argentina have declined, they are still higher than YPF’s target costs. The average drilling and completion cost of a horizontal well in Vaca Muerta was estimated to be $11.2 million as of 2015, compared to $6.5 million to $7.8 million in the Eagle Ford. Ultimately, the economic competitiveness of Argentina's indigenous shale gas resources will depend on the costs of domestic drilling and completion and the productivity of newly drilled wells. Although Argentina has an established energy industry, the current oil and gas sector is relatively small. The highest active rig count in Argentina in recent years was 110 for its nonshale oil and gas production, compared to more than 230 dedicated shale rigs in the Eagle Ford alone in 2013. Argentina has relatively high labor and imported equipment costs, shortages of specialized shale rigs, and limited proppant capacity—factors likely to hinder efforts to quickly increase production.

Average wholesale electricity prices at major trading hubs across the United States during the first quarter of 2016 were significantly lower than during the same period in 2015, ranging from 24% lower in California to 64% lower in New England. Monthly wholesale prices for the rest of 2016 were slightly below 2015 prices and generally averaged between $20 and $45 per megawatthour (MWh). The primary driver of the low wholesale electricity prices was the sustained low cost of natural gas, which is the fuel that often determines the marginal generation cost in most power markets. The low cost of natural gas also encouraged increased use of the fuel for U.S. power generation in 2016. The cost of natural gas delivered to power generators averaged $2.78 per million British thermal unit (Btu) during the first 10 months of 2016 (the latest data available), which was 17% lower than the average price during the same period in 2015. Milder winter weather in early 2016 also helped keep power prices lower than during the winter of 2014–15 when wholesale prices in the Northeast peaked in response to cold temperatures and constraints on getting fuel into the region. The average wholesale electricity price in ISO New England in February 2016 averaged $34/MWh, significantly lower than the $138/MWh average during February 2015. Wholesale power prices began slowly increasing in December as colder winter weather set in, which led to increasing natural gas prices. In addition to keeping wholesale power prices relatively stable in 2016, the low cost of natural gas contributed to a shift towards increased natural gas-fired electricity generation, largely at the expense of coal-fired generation. The amount of electricity generation fueled by natural gas between January and October 2016 was 6% higher than generation during the same period in 2015. In contrast, coal-fired electricity generation during the first 10 months of 2016 was down 12% compared with the same period in 2015. Natural gas was the primary source of U.S. electricity generation (when measured on an annual basis) in 2016 for the first time. Monthly natural gas-fired electricity generation first exceeded coal-fired generation as the primary source of electricity in April 2015. Natural gas was the leading source of electricity for nearly every month of 2016, accounting for an estimated 34% of total annual utility-scale power generation, compared with a 30% share for coal-fired generation. Electricity generating facilities were scheduled to add about 24 gigawatts (GW) of utility-scale capacity in 2016, more than 90% of which were natural gas, solar, and wind additions. Coal units accounted for most retirements during 2016, with more than 7 GW of coal-fired capacity retired during the year, equivalent to 2.5% of existing coal capacity in place at the end of 2015.

Fossil fuels—petroleum, natural gas, and coal—have accounted for at least 80% of energy consumption in the United States for well over a century. The fossil fuel share of total U.S. energy consumption in 2017 was the lowest share since 1902, at a little more than 80%, as U.S. fossil fuel consumption decreased for the third consecutive year. The decline in fossil fuel consumption in 2017 was driven by slight decreases in coal and natural gas consumption. Coal consumption fell by 2.5% in 2017, following larger annual declines of 13.6% and 8.5% in 2015 and 2016, respectively. U.S. consumption of coal peaked in 2005 and declined nearly 40% since then. Natural gas consumption fell by 1.4% in 2017, a change from recent trends. Unlike coal consumption, which has decreased in 8 of the past 10 years, natural gas consumption has increased in 8 of the past 10 years, and in 2017, was twice that of coal. Natural gas consumption growth has been driven by increased use in the electric power sector. Overall, U.S. consumption of natural gas increased by 24% from 2005 to 2017. Petroleum consumption increased in 2017, but remains 10% lower than its peak consumption level, also set in 2005. Mainly used in the transportation sector, several petroleum-based fuels are also used in homes, businesses, and industries. Petroleum has been the largest source of energy consumption in the United States since surpassing coal in 1950. The renewable share of energy consumption in 2017, which includes hydroelectricity, biomass, and other renewables such as wind and solar, was 11.3%, the highest since the late 1910s, when overall energy consumption was lower and biomass consumption—mainly wood—made up a larger share. The largest growth in renewables over the past decade has been in solar and wind electricity generation. Energy consumption in the United States has undergone many changes over the course of the nation’s history, from wood as the primary resource in the 18th and 19th centuries, to the onset of coal and petroleum use, to the more modern rise of nuclear power in the late 20th century, and to renewables in the early 21st century. Of course, EIA did not exist to collect data in 1776. The Monthly Energy Review's pre-1949 estimates of U.S. energy use are deeply indebted to two sources. Much of the data used in earlier energy estimates are from the book Energy in the American Economy 1850-1975, Its History and Prospects by Sam Schurr and Bruce Netschert. The U.S. Department of Agriculture’s Circular No. 641, Fuel Wood Used in the United States 1630–1930, published in 1942, provides some of the earliest biomass consumption estimates for the United States. Appendix D of EIA’s Monthly Energy Review compiles these estimates of U.S. energy consumption in ten-year increments from 1635 through 1845 and five-year increments from 1845 through 1945. Data for 1949 through the present day can be found in the latest Monthly Energy Review.

EIA expects construction of new natural gas pipeline capacity in the United States to continue in 2018, in particular in the northeastern United States. By the end of 2018, if all projects come online by their scheduled service dates, more than 23 billion cubic feet per day (Bcf/d) of takeaway capacity will be online out of the Northeast, up from an estimated 16.7 Bcf/d at the end of 2017 and more than three times the takeaway capacity at the end of 2014. Currently, the growth of natural gas production in the Marcellus and Utica basins in Pennsylvania, Ohio, and West Virginia is constrained by the lack of available takeaway pipeline capacity to move it to new markets. As new pipeline projects come online, they will create an outlet for increased production, providing natural gas to demand markets in the Midwest, the Southeast, eastern Canada, and the Gulf Coast. Currently, no major pipeline capacity expansions in advanced development are slated to come online in New England because of stakeholder concerns raised in the development process. Of the projects scheduled to be in service by the end of 2018, most are associated with four major interstate pipelines: Columbia Pipeline Group (TCO), which includes both Columbia Gas and Columbia Gulf Transmission; Transcontinental Gas Pipeline (Transco); Rover Pipeline; and NEXUS Pipeline. The Columbia Pipeline Group (TCO) has two expansion projects intended to add 4.2 Bcf/d of takeaway capacity out of the Northeast: Leach Xpress and Mountaineer Xpress. The Leach Xpress project, which entered service on January 1, 2018, supplies an additional 1.5 Bcf/d of capacity out of West Virginia and Ohio, and the Mountaineer Xpress project, which is scheduled to enter service in late 2018, will increase takeaway out of West Virginia by an additional 2.7 Bcf/d. As much as 2 Bcf/d of the natural gas from these two pipelines can be sent directly to the Gulf Coast via expansion projects on TCO’s Columbia Gulf pipeline, and the remainder will enter the TCO pool in Boyd County, Kentucky. Another TCO expansion project, the WB Xpress project, will increase mainline capacity to both the east (500 MMcf/d) and west (800 MMcf/d) when it is completed in late 2018. Three projects associated with the Transcontinental Gas Pipeline (Transco) are intended to add more than 3 Bcf/d of capacity out of Pennsylvania and West Virginia: Atlantic Sunrise, Mountain Valley Pipeline, and Equitrans Expansion. Atlantic Sunrise, the first phase of which was completed in 2017, is a nearly $3 billion project that will provide 1.7 Bcf/d of bidirectional capacity on the Transco System. The Mountain Valley Pipeline (2.0 Bcf/d), a new pipeline from West Virginia to the Transco system in southern Virginia, and the Equitrans Expansion Project (0.6 Bcf/d), which brings natural gas from northwest Pennsylvania to an interconnection with the Mountain Valley Pipeline, are also scheduled to come online in 2018. The first phase of Rover Pipeline was completed in late 2017, and Phase 2 is expected to come online in mid-2018. Phase 2 includes 3.25 Bcf/d of new capacity into Midwestern markets and the Dawn hub in Ontario, Canada. NEXUS Pipeline, which follows a similar route to Rover, will add 1.5 Bcf/d of new capacity. Natural gas from the Marcellus and Utica basins will be delivered to this pipeline by the 950 MMcf/d Appalachian Lease Project, also scheduled to come online in 2018. EIA is tracking more than 160 natural gas pipeline projects. Of these projects, 37 have been completed or are currently under construction and expected to come into service by the end of 2018. EIA’s Natural Gas Pipeline Projects tracker, updated quarterly, and EIA’s historical data for U.S. state-to-state pipeline capacities, are both available on EIA’s website.

Energy-related carbon dioxide (CO2) emissions fell in both 2015 and 2016, and they are expected to fall again in 2017, based on forecasts in EIA’s Short-Term Energy Outlook. However, EIA forecasts a 2.2% increase in energy-related CO2 emissions in 2018. An annual increase is not without recent precedent; annual emissions rose in 2010, 2013, and 2014, although U.S. energy-related CO2 emissions have generally been declining since reaching their peak in 2007. Weather is a key factor in annual changes in energy consumption and the resulting emissions. Weather-related energy demand can be estimated by changes in population-weighted degree days, which reflect deviations from a base temperature of 65 degrees Fahrenheit. Heating degree days estimate the need for heating-related energy demand on colder days, while cooling degree days indicate the need for cooling (air conditioning) on warmer days. By the end of 2017, annual heating degree days are expected to have been higher than in 2016, and cooling degree days are expected to have been lower. EIA’s short-term projections for heating and cooling degree days largely reflect a return to normal temperatures, based on the average of the previous 10 years. Consequently, in 2018, both heating and cooling demand are expected to increase, by 7.5% and 2.4%, respectively. These increases are expected to drive more energy consumption for heating—fueled by natural gas, electricity, and other fuels—and more energy consumption for air conditioning—fueled mostly by electricity. Because about 63% of the electricity generated in the United States is from coal and natural gas, increases in electricity consumption also mean more emissions from coal and natural gas power plants. In 2018, energy-related CO2 emissions are expected to increase for each fossil fuel—petroleum, natural gas, and coal—for a total increase of 111 million metric tons. The most recent year with emissions increases in all three fossil fuels was 2013, when emissions rose by 128 million metric tons from the previous year. Weather also plays a role in power generation from certain fuels. After two years of higher-than-average levels of precipitation in some areas, hydropower generation is projected to decrease in 2018 by 30 billion kilowatthours (kWh). Beyond hydro, increases in other renewable and nuclear generation (20 billion kWh and 4 billion kWh, respectively) are not enough to offset the expected hydropower decrease, leading non-carbon electricity generation to decline by 5 billion kWh. If realized, this would be the first annual decline in electricity generation from non-carbon sources since 2012. Because total power generation is expected to increase in 2018, electricity generation from coal- and natural gas-fired sources is projected to increase by a combined 97 billion kWh. The resulting increase in coal and natural gas CO2 emissions in the power sector—28 million and 29 million metric tons, respectively—combined accounts for 52% of the total projected increase in energy-related emissions in 2018.