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While most fossil fuels in the United States are burned, or combusted, to produce heat and power, EIA estimates that the equivalent of about 5.5 quadrillion British thermal units of fossil fuels were consumed for non-combustion purposes in the United States in 2017. Over the past decade, non-combustion consumption of fossil fuels has typically accounted for about 7% of total fossil fuel consumption and about 6% of total energy consumption in the United States.


Fossil fuels can be consumed, but not combusted, when they are used directly as construction materials, chemical feedstocks, lubricants, solvents, waxes, and other products. Common examples include petroleum products used in plastics, natural gas used in fertilizers, and coal tars used in skin treatment products. In 2017, about 13% of total petroleum products consumed were for non-combustion use. Natural gas non-combustion use accounted for about 3% of total natural gas, while coal was less than 1%.


In 2017, carbon dioxide (CO2) emissions would have been 196 million metric tons (about 4%) higher if non-combustion fuel use would have been combusted. Estimation of fossil fuels for non-combustion consumption is essential to calculate total U.S. carbon dioxide emissions. In the non-combustion use of these fuels, some (but not all) of the carbon is sequestered and not included in the fuel consumption values for emissions calculations.

U.S. non-combustion consumption by product type, as explained in the article text

Source: U.S. Energy Information Administration, Monthly Energy Review


Petroleum products account for about 86% of non-combustion consumption. Hydrocarbon gas liquids (HGL) such as ethane, ethylene, butane, butylene, isobutane, isobutylene, propylene, and natural gasoline and petrochemical feedstocks such as naphthas are important components for making plastics. HGL are used as intermediate products, while petrochemical feedstocks are used directly at chemical plants. Other petrochemical feedstocks are used to make synthetic fabrics, such as Kevlar, synthetic rubbers, detergents, and other chemical products.


Many other petroleum products are consumed for non-combustion uses other than plastics. Asphalt and road oils are used for roofing and paving construction. Lubricants, which include motor oil and greases, are used in vehicles, machinery, and various industrial processes. Petroleum coke is used as a chemical catalyst, while special naphthas are used in petroleum-based paints. Other petroleum products include distillate and residual fuel oils used as chemical feedstocks as well as polishes and waxes.


Relatively small amounts of natural gas are consumed for non-combustion use in the industrial sector. Natural gas is used as feedstock to make nitrogenous fertilizers and a range of chemical products including ammonia, hydrogen, and methanol.


Only small amounts of coal are used for non-combustion purposes in the industrial sector. Among the byproducts of the process to produce metallurgical coke are coal tars, which are rich in aromatic hydrocarbons, such as benzene, and are used as feedstocks in the chemical industry to make sealcoats for pavement, synthetic dyes, and paints. Some anti-dandruff shampoos and other medical skin care products contain coal tars.


Monthly and annual estimates of non-combustion consumption of fossil fuels are available in both physical units and energy units (British thermal units) in Tables 1.11a and 1.11b of EIA’s Monthly Energy Review.


Principal contributor: Mickey Francis

CO2 (carbon dioxide) coal consumption/demand emissions HGL (hydrocarbon gas liquid) liquid fuels natural gas oil/petroleum
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February, 17 2020
Your Weekly Update: 10 -14 February 2020

Market Watch   

Headline crude prices for the week beginning 10 February 2020 – Brent: US$53/b; WTI: US$49/b

  • The demand destruction caused by the Covid-19 pandemic – also known as the Wuhan coronavirus – has dragged crude prices to fresh lows, with OPEC+ struggling to present a united front to respond to the demand crisis
  • Earlier indications that OPEC+ was preparing to call for an emergency meeting mid-February to discuss the pandemic’s impact on the oil market were dashed, hinting at divisions within the oil club
  • Reportedly, OPEC’s technical committee was proposing to extend the club’s supply quota agreement through June 2020; Saudi Arabia – along with Iran and Bahrain – were the strongest supporters, but Russia remains reticent to commit
  • A group of key Russian oil producers are in support of extending the OPEC+ cuts, with Gazprom, Lukoil and Rosneft indicating that it ‘made sense’
  • In the face of the huge impact of Covid-19, the so-called Brent red spread sank into contango, indicating an intensely bear-ish market
  • Although the fatality rate of the new coronavirus is much lower than SARS, the spread has been far more severe and wider, with confirmed cases nearing 70,000 and deaths nearing 1,500
  • After being on lockdown for weeks, Chinese factories and businesses have gradually returned to work at a glacial pace, impacting gasoline, gasoil and - most significantly – jet fuel demand, causing Chinese refineries to slash output
  • News that China and the US would both implement tariff cuts on the pre-Phase 1 trade deal levies on February 14 failed to calm the market, supporting the floor for prices rather than raising the ceiling
  • Amid that chaos, the US active rig count dropped four rigs, falling down to 790 total and down 255 sites y-o-y; however, the relationship between this proxy and actual production has diminished over the past two years, as the US continues to produce more oil from less rigs
  • Hopes that the outbreak might have peaked has supported crude oil prices this year, although a major spike in confirmed cases from a wider diagnosis tool nipped that in the bud; expect crude oil prices to continue hovering around the US$50/b mark, at US$51-53/b for Brent and US$49-51/b for WTI


Headlines of the week

Upstream

  • Chevron and Petrobras will be selling their stakes in the heavy oil Papa-terra field in the Campos Basin, seeking new operatorship for the BC-20 concession asset that is currently split 62.5/37.5 between Petrobras and Chevron
  • Shell plans to boost its output in the Permian Basin to some 250,000 b/d by end-2020, up from a current production level of 100,000 b/d as it announced plans to invest up to US$3 billion per year in the prolific US shale area
  • Eni’s oil production in Libya has halved to 160,000 b/d, as the country continues to grapple with a blockade started by military strongman Khalifa Haftar
  • Disappointing results in Africa have forced Tullow Oil to reduce its headcount in Kenya by 40%, with operations in Kenya, Uganda and Ghana all yielding either poor results or in danger of significant delays
  • BP and Shell have brought the Alligin field in the UK West of Shetlands region online, with initial output at a better-than-expected 12,000 b/d
  • Guyana’s oil riches keep increasing; after ExxonMobil upped estimates at the Stabroek block last month, Eco Atlantic (together with Tullow Oil and Total) have upped reserves in the Orinduik block from 3.98 mmboe/d to 5.14 mmboe/d

Midstream/Downstream

  • Reports suggest that Chinese independent teapot refineries in Shandong have slashed their utilisation rates by 30-50%, scaling down in response to severely diminished fuel and petrochemicals demand due to the Covid-19 pandemic
  • Chinese state refiners are following suit with slashing output, with CNOOC, Sinopec and PetroChina all lowering their throughput rates by 10-15%
  • Shell has finalised the sale of its Martinez refinery in California, selling it to PBF Energy for some US$1.2 billion, including its supply/offtake agreements
  • Botswana is accelerating its US$4 billion coal-to-liquids refinery project, now expecting to complete the site by 2025, with the aim of tapping into the country’s major coal reserves that are some of the largest in Africa
  • The UK has extended its goal to end the sale of all gasoline- and diesel-powered vehicles in the UK by 2035 to include hybrid vehicles, which would move transport fuel demand entirely to electric vehicles then

Natural Gas/LNG

  • Abu Dhabi and Dubai report that they have made a major natural gas find, with the Jebel Ali reservoir located between the two largest sheikhdoms in the UAE holding some 80 tcf of resources - the world’s largest gas find in 15 years
  • The government of Papua New Guinea has walked away from talks over the P’nyang gas field, impacting the planned expansion of ExxonMobil’s PNG LNG project; the government had previously tried a similar tactic with Total
  • The EU has imposed sanctions on Turkey, in retaliation for its continued exploration of gas resources in the disputed waters off Cyprus that Turkey claims is part of the breakaway Turkish province in the north of the island
  • CNOOC has declared force majeure on some LNG contracts due to the ongoing impact of the Covid-19 outbreak, but two of the world’s largest LNG traders – Shell and Total – have rejected the Chinese attempt to nullify contractual terms
  • Centrica will take a major write-down on its gas assets in Europe, continuing a trend of the global natural gas glut eroding the value of gas assets worldwide
  • GeoPark has made a new natural gas discovery in Chile, with the Jauke Oeste field in the Fell block of the Magallanese Basin yielding small-but-significant gas flows of some 4.4 mscf/d
February, 14 2020
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • EIA expects global petroleum and liquid fuels demand will average 100.3 million barrels per day (b/d) in the first quarter of 2020. This demand level is 0.9 million b/d less than forecast in the January STEO and reflects both the effects of the coronavirus and warmer-than-normal January temperatures across much of the northern hemisphere. EIA now expects global petroleum and liquid fuels demand will rise by 1.0 million b/d in 2020, which is lower than the forecast increase in the January STEO of 1.3 million b/d in 2020, and by 1.5 million b/d in 2021.
  • EIA’s global petroleum and liquid fuels supply forecast assumes that the Organization of the Petroleum Exporting Countries (OPEC) will reduce crude oil production by 0.5 million b/d from March through May because of lower expected global oil demand in early 2020. This OPEC reduction is in addition to the cuts announced at the group’s December 2019 meeting. EIA now forecasts OPEC crude oil production will average 28.9 million b/d in 2020, which is 0.3 million less than forecast in the January STEO. In addition to these production cuts, EIA’s lower forecast OPEC production reflects ongoing crude oil production outages in Libya during the first quarter. In general, EIA assumes that OPEC will limit production through all of 2020 and 2021 to target relatively balanced global oil markets.
  • Global liquid fuels inventories fell by roughly 0.1 million b/d in 2019, and EIA expects they will grow by 0.2 million b/d in 2020. Although EIA expects inventories to rise overall in 2020, EIA forecasts inventories will build by 0.6 million b/d in the first half of the year because of slow oil demand growth and strong non-OPEC oil supply growth. Firmer demand growth as the global economy strengthens and slower supply growth later in the year contribute to forecast inventory draws of 0.1 million b/d in the second half of 2020. EIA expects global liquid fuels inventories will decline by 0.2 million b/d in 2021.
  • Brent crude oil spot prices averaged $64 per barrel (b) in January, down $4/b from December. Brent prices fell steadily through January and into the first week of February, closing at less than $54/b on February 4, the lowest price since December 2018, reflecting market concerns about oil demand. EIA forecasts Brent prices will average $61/b in 2020; with prices averaging $58/b during the first half of the year and $64/b during the second half of the year. EIA forecasts the average Brent prices will rise to an average of $68/b in 2021.

Natural gas

  • In January, the Henry Hub natural gas spot price averaged $2.02 per million British thermal units (MMBtu), as warm weather contributed to below-average inventory withdrawals and put downward pressure on natural gas prices. As of February 6, the Henry Hub spot price had fallen to $1.86/MMBtu, and EIA expects prices will remain below $2.00/MMBtu in February and March. EIA forecasts that prices will rise in the second quarter of 2020, as U.S. natural gas production declines and natural gas use for power generation increases the demand for gas. EIA expects prices to average $2.36/MMBtu in the third quarter of 2020. EIA forecasts that Henry Hub natural gas spot prices will average $2.21/MMBtu in 2020. EIA expects that natural gas prices will then increase in 2021, reaching an annual average of $2.53/MMBtu.
  • U.S. dry natural gas production set a record in 2019, averaging 92.1 billion cubic feet per day (Bcf/d). Although EIA forecasts dry natural gas production will average 94.2 Bcf/d in 2020, a 2% increase from 2019, EIA expects monthly production to generally decline through 2020, falling from an estimated 95.4 Bcf/d in January to 92.5 Bcf/d in December. The falling production mostly occurs in the Appalachian and Permian regions. In the Appalachia region, low natural gas prices are discouraging natural gas-directed drilling, and in the Permian, low oil prices are expected to reduce associated gas output from oil-directed wells. In 2021, EIA forecasts dry natural gas production to stabilize near December 2020 levels at an annual average of 92.6 Bcf/d, a 2% decline from 2020, which would be the first decline in annual average natural gas production since 2016.
  • EIA estimates that U.S. working natural gas inventories ended January at more than 2.6 trillion cubic feet (Tcf), 9% higher than the five-year (2015–19) average. EIA forecasts that total working inventories will end March at almost 2.0 Tcf, 14% higher than the five-year average. In the forecast, inventories rise by a total of 2.1 Tcf during the April through October injection season to reach almost 4.1 Tcf on October 31, which would be the highest end-of-October inventory level on record.

Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. utility-scale electricity generation from natural gas-fired power plants will remain relatively steady; it was 37% in 2019, and EIA forecasts it will be 38% in 2020 and 37% in 2021. Electricity generation from renewable energy sources will rise from a share of 17% last year to 20% in 2020 and 21% in 2021. The increase in the renewables share is the result of expected use of additions to wind and solar generating capacity. Coal’s forecast share of electricity generation will fall from 24% in 2019 to 21% in both 2020 and 2021. The nuclear share of generation, which averaged slightly more than 20% in 2019 will be slightly lower than 20% by 2021, consistent with upcoming reactor retirements.
  • EIA forecasts that U.S. coal production will total 595 million short tons (MMst) in 2020, down 95 MMst (14%) from 2019. Lower production reflects declining demand for coal in the electric power sector and lower demand for U.S. exports. EIA forecasts that electric power sector demand for coal will fall by 81 MMst (15%) in 2020. EIA expects that coal production will stabilize in 2021 as export demand stabilizes and U.S. power sector demand for coal increases because of rising natural gas prices.
  • After decreasing by 2.3% in 2019, EIA forecasts that energy-related carbon dioxide (CO2) emissions will decrease by 2.7% in 2020 and by 0.5% in 2021. Declining emissions in 2020 reflect forecast declines in total U.S. energy consumption because of increases in energy efficiency and weather effects, particularly as a result of warmer-than-normal January temperatures. A forecast return to normal temperatures in 2021 results in a slowing decline in emissions. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.
February, 12 2020