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Last Updated: January 16, 2020
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monthly Henry Hub natural gas spot prices

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that average U.S. natural gas prices will be 9% lower in 2020 than in 2019. EIA expects lower natural gas prices will be the result of continued production growth primarily in response to the following factors:

  • Improved drilling efficiency and cost reductions
  • Higher associated gas production from oil-directed rigs
  • Increased takeaway pipeline capacity from the Appalachian and Permian production regions  

This production growth outpaces the growth in domestic demand and exports.

EIA expects the natural gas spot price for the U.S. benchmark Henry Hub will average $2.33 per million British thermal units (MMBtu) in 2020, about 24 cents lower than the 2019 average of $2.57/MMBtu. Following a year of decline, EIA expects 2021 natural gas prices to rise by 9% because of upward pricing pressure from declining growth in natural gas production.

annual U.S. natural gas consumption and production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

EIA expects record volumes of U.S. dry natural gas production to continue through 2020, from an estimated 92.0 billion cubic feet per day (Bcf/d) in 2019 to 94.7 Bcf/d in 2020. Most U.S. production will come from the Appalachian Basin in the Northeast, followed by the Permian Basin in western Texas and New Mexico and the Haynesville shale formation in eastern Texas. Cost reductions in drilling and well completions and improved drilling efficiency will support continued record-production levels in 2020. In addition, a growing share of natural gas production is coming from oil wells that produce natural gas, also called associated gas. Increased takeaway capacity from the highly productive Appalachian and Permian production regions will further enable growth. However, in 2021, EIA expects dry natural gas production to decline by less than 1% to 94.1 Bcf/d in response to lower forecast natural gas spot prices in 2020, which would reduce Appalachian Basin production.

Total U.S. natural gas consumption remains relatively unchanged compared with 2019 levels in the STEO forecast, increasing 1.7% in 2020, but decreasing 1.2% in 2021 to an average 85.7 Bcf/d in 2021. EIA forecasts natural gas consumption to decrease slightly in the residential and commercial sectors as a result of expected milder weather that will require less energy for space heating in the winter and air conditioning in the summer. Based on forecasts by the National Oceanic and Atmospheric Administration, EIA forecasts 1.8% fewer heating degree days (HDD) in 2020 compared with 2019, which had a colder-than-normal first quarter.

EIA expects U.S. natural gas use in the electric power sector to increase by 1.3% in 2020 as a result of natural gas-fired generation additions that continue to displace coal-fired generation. However, in 2021, because of a forecast of higher natural gas spot prices and increased competition from renewables, EIA estimates that natural gas consumption in the electric power sector will decline by 3.2% in 2021. EIA expects the natural gas share of electricity generation in 2021 to be 37%, about the same as its 2019 share, while coal’s share of electricity generation will fall from 24% in 2019 to 21% in 2021.

Natural gas consumption in the U.S. industrial sector will continue to grow in 2020, increasing by 4.6%. New methanol plants that use natural gas as feedstock are scheduled to come online in 2020, which will support the increased industrial sector consumption. In 2021, EIA expects industrial sector consumption to flatten because of higher industrial sector natural gas prices.

annual U.S. natural gas trade

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

The United States became a net exporter of natural gas on an annual basis for the first time in 2018, and EIA expects that this trend will continue during the forecast period. In 2020, net exports will average 7.3 Bcf/d—an increase of 2.0 Bcf/d over the 2019 levels. EIA expects 2021 net exports to rise further to 8.9 Bcf/d as new liquefied natural gas (LNG) projects enter service. The remaining trains at the Cameron LNG and Freeport LNG facilities, located along the Gulf Coast, and the Elba Island LNG facility in Georgia will be placed into service in 2020. EIA expects LNG exports to increase from an estimated 5.0 Bcf/d in 2019 to 6.5 Bcf/d in 2020 and up to 7.7 Bcf/d in 2021, more than double the 2018 level.

EIA forecasts that gross exports of natural gas by pipeline will continue to grow, increasing to 8.1 Bcf/d in 2020 and 8.5 Bcf/d in 2021, or 8.8% higher than the 2019 level. Most of the increase will be driven by increasing natural gas demand and by pipeline projects in Mexico that are scheduled to come online by the end of 2021. EIA expects imports of LNG to remain flat through 2021, and imports by pipeline will continue to decrease through 2020, when Appalachian production and takeaway capacity displace imported natural gas from Canada in the U.S. Midwest markets.

natural gas production supply consumption demand exports imports STEO EIA
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EIA expects U.S. energy-related CO2 emissions to decrease annually through 2021

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.

U.S. annual carbon emissions by source

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020
Note: CO2 is carbon dioxide.

January, 21 2020
Latest issue of GEO ExPro magazine covers Europe and Frontier Exploration, Modelling and Mapping, and Geochemistry.

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.

You can download the PDF of GEO ExPro magazine for FREE and sign up to GEO ExPro’s weekly updates and online exclusives to receive the latest articles direct to your inbox.

Download GEO ExPro Vol. 16, No. 6

January, 20 2020
Your Weekly Update: 13 - 17 January 2020

Market Watch   

Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b

  • Tensions in the Persian Gulf have abated, but not disappeared, as both the US and Iran stepped back from going to war; the buck, so far, has stopped with Tehran’s retaliation to the US assassination of its top general with a barrage of missile strikes at US bases in Iraq
  • The underlying situation is still fragile, with the Iranian population swinging from supporting the government to protesting its accidental downing of a commercial Ukraine Airlines plane; with the risk of war easing, crude prices have fallen back to their pre-crisis levels
  • However, American and foreign oil companies have pulled their staff from crude fields in northern Iraq and Kurdistan, including Chevron, as the oil industry in Iraq monitors the risk – and consequences – of military action
  • In precaution, oil tankers have begun boosting their rates once again to haul crude through the Persian Gulf, with quoted rates now at their highest level since the 2019 attacks on ships passing through the narrow straight
  • Although political tensions remain fresh, Saudi Arabia said that OPEC and the OPEC+ club were instead focused on using their window of production cuts to reduce excess oil stockpiles to levels ‘within the contours of 2010-2014’
  • In the US, not only is shale output staying strong, but production in the US Gulf of Mexico also made history, exceeding 2 mmb/d for the first time ever in 2019, beating the previous high recorded in 2018
  • Worries about the health of global oil demand persist… although the US and China signed a Phase 1 trade deal, the agreement is more about halting escalation of the trade war than repairing inflicted damage; a slowdown in Chinese economic growth could lead to oil demand growth halving in 2020 in China according to CNPC
  • The US active rig count fell for a second consecutive week, losing 15 rigs – 11 oil and 4 gas – for the 17th weekly decline of the past 20 weeks; losses in the Permian were once again high, shedding a total of 6 rigs
  • Crude oil prices should remain rangebound with Brent at US$63-65/b and WTI at US$57-59/b, as the market retreats back to its ever-present worries about demand while geopolitical risk premiums scale back


Headlines of the week

Upstream

  • Guyana’s success is now extending to its neighbours, with Total and Apache announcing a ‘significant’ oil discovery at their Maka Central-1 well in Suriname’s Block 58, which lies adjacent to the prolific Stabroek Block
  • BP has agreed to sell its operating interest in the UK North Sea’s Andrew assets – including the Andrew platform as well as the Andrew, Arundel, Cyrus, Farragon, and Kinnoull fields – along with its 27.5% non-operating interest in the Shearwater field to Premier Oil for some US$625 million
  • Liberia will kick start its next offshore licensing round in April 2020, offering nine blocks in the Harper basin, one of the few offshore regions in West Africa that remains unexplored and undrilled
  • Equinor has extended the life of its Statfjord assets beyond 2030, with plans to commission up to 100 new wells over the next decade, deferring decommissioning with a goal of maintaining current output levels beyond 2025
  • After Murphy Oil, Petrofac and ExxonMobil, Repsol is the latest major considering an upstream exit from Malaysia, covering assets that include six development blocks and the major Kinabalu oilfield in Sabah
  • Senegal’s government has approved Woodside’s offshore Sangomar Field Development, which will involve the drilling of 23 subsea wells and a FPSO with the capacity to process up to 100,000 b/d of crude
  • Equinor has announced plans to reduce greenhouse gas emissions from its offshore fields and onshore plants in Norway by 40% by 2030, 70% by 2040 and to near zero by 2050 from 2019 levels

Midstream/Downstream

  • Shell is reportedly seeking buyers for its 144 kb/d Anacortes refinery in Washington state, which would be its third North American sale in two years after divesting its Martinez refinery in California and Sarnia refinery in Ontario
  • Shell has announced plans to increase its share of the Mexican fuel market to 15%, which would require considerable growth in its network of 200 fuel stations in 12 states that currently represent 1% of the market
  • Occidental Petroleum plans to reduce its holdings in Western Midstream Partners – acquired as part of its controversial takeover of Anadarko – to less than 50%, potentially removing up to US$7.8 billion of debt

Natural Gas/LNG

  • Sempra Energy and Saudi Aramco have signed an agreement that will see the Saudi giant play a bigger part in the planned 22 million tpa Port Arthurt LNG project, following an existing agreement to purchase 5 mtpa signed in May 2019
  • Kuwait Petroleum Corp has agreed to purchase 3 million tpa of LNG from Qatar Petroleum for 15 years beginning 2022, with Kuwait remaining one of the few countries in the Middle East that remain neutral to the Saudi-Qatar standoff
  • ExxonMobil has signed an agreement with midstream company Outrigger Energy II to build a 250 mmscf/d cryogenic gas processing, gathering and pipeline system in the Bakken’s Williston Basin in North Dakota
  • The Larak gas field in Sarawak has achieved first gas, operated by SapuraOMV Upstream as part of the SK408 PSC that includes the Gorek and Bakong fields, with output planned to be processed into LNG at Petronas’ Bintulu complex
  • Russia’s TurkStream natural gas pipeline – connecting Russia, Turkey, Bulgaria and eventually Serbia and Hungary - has officially begun operations, delivering up to 13 bcm of Russian gas that can be rerouted from the Ukraine route
January, 17 2020