In 2019, natural gas spot prices at the national benchmark Henry Hub in Louisiana averaged $2.57 per million British thermal units (MMBtu), about 60 cents per MMBtu lower than in 2018 and the lowest annual average price since 2016. Lower natural gas prices in 2019 supported higher consumption—particularly in the electric generation sector—and higher natural gas exports. Continued growth in domestic production of natural gas also supported lower natural gas prices throughout the year.
Monthly average natural gas prices at most key regional trading hubs in 2019 reached their highest levels in February, and they were relatively low and stable from April through December. In the Northeast, additional imports of liquefied natural gas (LNG) into New England limited price spikes during the winter of 2018–19. Despite a cold snap in the Midwest in February 2019, natural gas prices at Chicago Citygate were lower than during previous extreme weather events.
However, in the Pacific Northwest, unseasonably cold weather at the end of winter coupled with regional supply constraints and decreased storage inventories led to significant price spikes at the Northwest Sumas hub in March. Additional pipeline takeaway capacity in the Permian region eased some infrastructure constraints and increased regional prices at the Waha hub in western Texas after six consecutive months of prices lower than $1/MMBtu (March through August).
Source: U.S. Energy Information Administration, based on Natural Gas Intelligence
Natural gas consumption in the residential and commercial sectors increased by 2% in 2019 compared with 2018, based on the U.S. Energy Information Administration’s (EIA) monthly data through October and estimates for November and December. Natural gas use in the electric generation sector also increased in 2019, particularly in July and August when a heat wave in the Midwest and the Northeast led to record-high generation by natural gas-fired power plants.
Lower summer natural gas prices, which averaged $2.33/MMBtu in June through August (the lowest summer average Henry Hub natural gas price since 1998), have supported higher natural gas-fired generation in the summer months.
Dry natural gas production has grown every year since 2016. Production increased by 7.5 billion cubic feet per day (Bcf/d) (9%) through the first 10 months of the year after record growth in 2018. Sustained growth in natural gas production put downward pressure on prices, which continued to decline for most of 2019.
Natural gas storage inventories ended the withdrawal season at the end of March at their lowest levels since 2014. However, record natural gas production growth supported near-record injection activity during the injection season through October. The injection season ended with the second-highest net injection volume since 2014.
Most new pipelines placed in service in 2019 were located in the South Central and Northeast regions. These pipelines provide additional takeaway capacity out of the Permian and Appalachian supply basins and will serve growing demand for LNG exports, pipeline exports to Mexico, and U.S. natural gas-fired power generation.
In 2019, natural gas exports—both by pipeline to Mexico and as LNG—continued to grow. U.S. natural gas exports to Mexico by pipeline averaged 5.1 Bcf/d in the first 10 months of 2019, 0.4 Bcf/d more than the 2018 average. Following an expansion in U.S. cross-border pipeline capacity, several new pipelines in Mexico continued to experience delays, limiting growth in exports.
U.S. LNG exports set a new record in 2019, averaging an estimated 5.0 Bcf/d (69% higher than in 2018) as the United States became the third-largest global LNG exporter. Several new LNG facilities were placed in service in 2019. Louisiana’s Cameron LNG placed its first liquefaction unit (referred to as a train) in service in May. Texas’s Freeport LNG exported its first cargo from the newly commissioned Train 1 in September, followed by its first export cargo from Train 2 in December. Corpus Christi LNG (also in Texas) commissioned its second train in July. In December, Georgia’s Elba Island placed in service the first three of its moveable modular liquefaction system (MMLS) units and exported its first LNG cargo.
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In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts year-over-year decreases in energy-related carbon dioxide (CO2) emissions through 2021. After decreasing by 2.1% in 2019, energy-related CO2 emissions will decrease by 2.0% in 2020 and again by 1.5% in 2021 for a third consecutive year of declines.
These declines come after an increase in 2018 when weather-related factors caused energy-related CO2 emissions to rise by 2.9%. If this forecast holds, energy-related CO2 emissions will have declined in 7 of the 10 years from 2012 to 2021. With the forecast declines, the 2021 level of fewer than 5 billion metric tons would be the first time emissions have been at that level since 1991.
After a slight decline in 2019, EIA expects petroleum-related CO2 emissions to be flat in 2020 and decline slightly in 2021. The transportation sector uses more than two-thirds of total U.S. petroleum consumption. Vehicle miles traveled (VMT) grow nearly 1% annually during the forecast period. In the short term, increases in VMT are largely offset by increases in vehicle efficiency.
Winter temperatures in New England, which were colder than normal in 2019, led to increased petroleum consumption for heating. New England uses more petroleum as a heating fuel than other parts of the United States. EIA expects winter temperatures will revert to normal, contributing to a flattening in overall petroleum demand.
Natural gas-related CO2 increased by 4.2% in 2019, and EIA expects that it will rise by 1.4% in 2020. However, EIA expects a 1.7% decline in natural gas-related CO2 in 2021 because of warmer winter weather and less demand for natural gas for heating.
Changes in the relative prices of coal and natural gas can cause fuel switching in the electric power sector. Small price changes can yield relatively large shifts in generation shares between coal and natural gas. EIA expects coal-related CO2 will decline by 10.8% in 2020 after declining by 12.7% in 2019 because of low natural gas prices. EIA expects the rate of coal-related CO2 to decline to be less in 2021 at 2.7%.
The declines in CO2 emissions are driven by two factors that continue from recent historical trends. EIA expects that less carbon-intensive and more efficient natural gas-fired generation will replace coal-fired generation and that generation from renewable energy—especially wind and solar—will increase.
As total generation declines during the forecast period, increases in renewable generation decrease the share of fossil-fueled generation. EIA estimates that coal and natural gas electric generation combined, which had a 63% share of generation in 2018, fell to 62% in 2019 and will drop to 59% in 2020 and 58% in 2021.
Coal-fired generation alone has fallen from 28% in 2018 to 24% in 2019 and will fall further to 21% in 2020 and 2021. The natural gas-fired generation share rises from 37% in 2019 to 38% in 2020, but it declines to 37% in 2021. In general, when the share of natural gas increases relative to coal, the carbon intensity of the electricity supply decreases. Increasing the share of renewable generation further decreases the carbon intensity.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
Note: CO2 is carbon dioxide.
GEO ExPro Vol. 16, No. 6 was published on 9th December 2019 bringing light to the latest science and technology activity in the global geoscience community within the oil, gas and energy sector.
This issue focusses on oil and gas exploration in frontier regions within Europe, with stories and articles discussing new modelling and mapping technologies available to the industry. This issue also presents several articles discussing the discipline of geochemistry and how it can be used to further enhance hydrocarbon exploration.
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Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b
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