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Last Updated: January 9, 2020
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The international benchmark Brent crude oil futures price averaged $64 per barrel (b) in 2019, $7/b lower than its 2018 average. The U.S. benchmark West Texas Intermediate (WTI) futures price averaged $57/b in 2019, also $7/b lower than its 2018 average. Compared with recent years, both crude oil prices traded within relatively narrow price ranges in 2019. Brent prices reached a 2019 annual daily low of $55/b in early January and a daily high of $75/b in late April, resulting in a range of $20/b, the narrowest Brent price range since 2003. WTI prices ranged $19/b between $47/b and $66/b, the narrowest WTI price range since 2003. These narrow trading ranges occurred as a result of offsetting upward and downward price pressures, despite the largest single-day price increase since 2008, which followed the September attacks on Saudi Arabia’s crude oil production and processing infrastructure. More recently, crude oil prices have increased following the January 3, 2020, U.S. military operation in Iraq, likely reflecting an increase in geopolitical risk.

Figure 1.

On September 14, 2019, an attack damaged the Saudi Aramco Abqaiq oil processing facility and the Khurais oil field in eastern Saudi Arabia. With a capacity of 7 million barrels per day (b/d), or about 7% of global crude oil production capacity, the Abqaiq oil processing facility is the world’s largest crude oil processing and stabilization plant. On Monday, September 16, 2019, the first full day of trading after the attack, Brent and WTI crude oil prices increased by $9/b and $8/b, respectively. However, the price increase did not affect the annual range because prices following the attacks did not rise higher than prices in April. The price increase was also relatively short-lived, and prices for both Brent and WTI fell below pre-attack levels by October 1.

Saudi crude oil production fell to 8.5 million b/d in September but returned to pre-attack levels in October, averaging 9.9 million b/d for the month. From January through November 2019, Saudi crude oil production averaged 9.8 million b/d, 590,000 b/d less than the average during the same period in 2018. The year-to-date production decline is largely the result of a production cut agreement between members of the Organization of the Petroleum Exporting Countries (OPEC) and ten additional non-member countries including Russia, Mexico, and Kazakhstan (OPEC+).

In its December Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecast that OPEC crude oil production would average 29.8 million b/d in 2019, down from 32.0 million b/d in 2018. In addition to production declines in Saudi Arabia, the decrease in total OPEC output was largely driven by falling production in Venezuela and Iran due, in part, to U.S. sanctions. Crude oil production in Venezuela averaged 820,000 b/d through November 2019, a decline of 620,000 b/d from the same period in 2018. Iranian crude oil production fell by 1.3 million b/d through November 2019 compared with the same period in 2018.

In 2019, several factors, including U.S. production and exports, global inventory levels, and demand-side concerns, provided downward pressure on crude oil prices, offsetting some of the upward pressure from the attacks on Saudi Arabia, OPEC+ production cuts, and U.S. sanctions on Venezuela and Iran.

In the December STEO, EIA expected U.S. crude oil production to average 12.3 million b/d in 2019, the highest level on record. EIA crude oil production data are available beginning in 1990. If the December STEO forecast is realized, the year-over-year growth of U.S. crude oil production in 2019 would be 1.3 million b/d, down slightly from the growth of 1.6 million b/d in 2018. Final monthly 2019 crude oil production data will be available at the end of February 2020 when the Petroleum Supply Monthly is released.

Based on monthly data for January through October, U.S. crude oil exports averaged 2.9 million b/d during that period in 2019, 920,000 b/d more than exported during the same period in 2018. Through October, crude oil was the largest U.S. petroleum export in 2019 followed by distillate (1.3 million b/d), propane (1.1 million b/d), and gasoline (0.9 million b/d) (Figure 2). September and October were the first two months on record that the United States exported more petroleum, including both crude oil and petroleum products, than it imported.

Figure 2.

High U.S. crude oil production and exports helped supply the global petroleum market and contributed to higher-than-average inventory levels. Although EIA does not directly collect data on changes in global petroleum inventories, inventory data for countries within the Organization for Economic Cooperation and Development (OECD) provide some insight into the global balance. In the December STEO, EIA forecasts that OECD inventories in 2019 will average 2.9 billion barrels, 2% more than the previous five-year (2014–18) average.

During 2019, market concerns regarding global demand also provided downward pressure on crude oil prices. As a result of declining economic indicators and downward revisions to global gross domestic product (GDP) growth forecast (EIA bases its oil-weighted GDP forecast on work by Oxford Economics), EIA lowered its global liquid fuels consumption forecast (Figure 3). In the December STEO, EIA forecast that global petroleum consumption in 2019 would average 100.7 million b/d, which, if realized, would be the first time annual growth averaged less than 1.0 million b/d since 2011.

Figure 3.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price rose nearly 1 cent from the previous week to $2.58 per gallon on January 6, 34 cents higher than the same time last year. The East Coast price rose nearly 4 cents to $2.54 per gallon. The Rocky Mountain price fell more than 2 cents to $2.64 per gallon, the Midwest price fell nearly 2 cents to $2.43 per gallon, the West Coast price fell more than 1 cent to $3.21 per gallon, and the Gulf Coast price fell nearly 1 cent, remaining virtually unchanged at $2.28 per gallon.

The U.S. average diesel fuel price rose 1 cent from the previous week to $3.08 per gallon on January 6, 7 cents higher than a year ago. The East Coast price rose more than 2 cents to $3.12 per gallon, and the Gulf Coast price increased 2 cents to $2.83 per gallon. The Rocky Mountain price declined more than 1 cent to $3.10 per gallon, the West Coast price fell nearly 1 cent to $3.62 per gallon, and the Midwest price fell less than 1 cent, remaining virtually unchanged at $2.98 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 0.7 million barrels last week to 88.9 million barrels as of January 3, 2020, 12.5 million barrels (16.3%) greater than the five-year (2015-19) average inventory levels for this same time of year. Gulf Coast and East Coast inventories increased by 1.2 million barrels and 0.4 million barrels, respectively. Midwest and Rocky Mountain/West Coast inventories decreased by 0.6 million barrels and 0.3 million barrels, respectively. Propylene non-fuel-use inventories represented 6.9% of total propane/propylene inventories.

Residential heating oil prices increase, propane prices decrease

As of January 6, 2020, residential heating oil prices averaged more than $3.12 per gallon, almost 5 cents per gallon above last week’s price and more than 3 cents per gallon higher than last year’s price at this time. Wholesale heating oil prices averaged almost $2.17 per gallon, nearly 1 cent per gallon higher than last week’s price and almost 28 cents per gallon higher than a year ago.

Residential propane prices averaged almost $2.01 per gallon, nearly 1 cent per gallon below last week’s price and almost 43 cents per gallon less than a year ago. Wholesale propane prices averaged $0.66 per gallon, more than 5 cents per gallon lower than last week’s price and nearly 11 cents per gallon below last year’s price.

consumption demand crude oil exports imports oil petroleum prices 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