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Last Updated: July 13, 2018
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Headline crude prices for the week beginning 9 July 2018 – Brent: US$78/b; WTI: US$73/b

  • Tensions over the looming sanctions on Iran – and the US appearing to take a hardline stance over waivers and exemptions – continue to keep crude prices high, supported by the outage in Canadian Syncrude production and falling Libyan production.
  • The trade spat between China and the US has now led to President Trump proposing tariffs on an additional US$200 billion worth of Chinese imports. China has threatened to retaliate, suggesting a 25% duty on US energy imports, a development that would rattle Trump’s key supporters.
  • South Korean and European refiners have already reduced their purchases to virtually zero, as Iran threatens to blockade the Strait of Hormuz in retaliation to US trade sanctions while the EU tries to save the Iranian nuclear deal.
  • As President Trump continues to complain over high oil prices on Twitter, publicly blaming OPEC and Saudi Arabia, Iran has taunted Trump by saying that his tweets have ‘added US$10 to oil prices’, requesting him to stop.
  • Libyan production is also fast becoming a concern, adding to OPEC’s headache with Venezuela and Iran, with output in Libya halving over the last five months to 527,000 b/d despite attempts to boost output.
  • The outage at the Syncrude plant in Alberta will continue through July, keeping the Brent-WTI differential narrow.
  • US drillers snapped two weeks of losses to add five rigs – all oil – to the active rig count, as drillers responded to stronger price signals.
  • Crude price outlook: The current range of factors keeping crude prices tight will continue, with some possible downward correction this week. We expect Brent to range in US$75-76/b and US$71-72/ for WTI.

Headlines of the week

Upstream

  • Chevron is looking to exit the UK Central North Sea, beginning the process of ‘marketing its assets’ including the Alba, Alder, Britannia, Captain, Elgin/Franklin, Erskine and Jade fields.
  • BP and its partners have sanctioned startup of the Shah Deniz 2 gas development in Azerbaijan, adding 16 bcm/y of capacity to total production.
  • BP will buy ConocoPhillips’ 16.5% stake in the UK North Sea Clair field, increasing its stake to 45.1%. In Alaska, BP has sold its 39.2% interest in the North Slope Greater Kuparuk Area to the Kuparuk Transportation Company.
  • China’s CNPC and Abu Dhabi’s ADNOC will be signing an agreement to cooperate on oil and gas exploration and refining projects later this month.
  • CNOOC has signed a new PSC for the Weizhou 10-3W oilfield and Block 22/04 in the South China Sea’s Beibu Gulf Basin with Roc Oil and Smart Oil.
  • In an effort to boost domestic output, Russia’s parliament is moving to approve a new profit-based taxation scheme for a select number of oilfields that could conceivably boost production by some 18,000 b/d.

Downstream

  • The Hovensa refinery in St. Croix, US Virgin Islands will be restarted, after being idled in 2012, in a US$1.4 billion plan to produce low-sulfur fuels and fill the growing hole in Caribbean refining created by PDVSA’s implosion.
  • Ineos has approved the first new ethane cracker in Europe for two decades, investing €2.7 billion in a cracker and PDH unit in Northern Europe to take advantage of US shale gas economics and support its olefins business.
  • With Egypt completing its natural gas revolution, the industry is moving further downstream as Carbon Holding is looking to start the US$10.9 billion Tahrir Petrochemicals Company complex in the Suez Canal Economic Zone.
  • The US$10 billion Dangote refinery being developed in Nigeria is now planning for an early-2020 start, with a capacity now planned for 650 kb/d.
  • Pemex has sold its 44.08% stake in chemical firm Petroquimica Mexicana de Vinilo to Mexichem for US$178.7 million.
  • Petronas has bought its first ever US cargo – 1 million barrels of Mars crude – to arrive at its Melaka refinery in September, replacing Middle Eastern crude.

Natural Gas/LNG

  • Gas production at Eni’s Sankofa field in Ghana’s Offshore Cape Three Points project has started, providing 180 mmscf/d for at least 15 years.
  • Eni has also started output at the Bahr Essalam Phase 2 project in Libya, which will raise production potential by 400 mmscf/d to 1.1 MMscf/d.
  • Vandalism has halted construction on ExxonMobil’s Angore gas pipeline connecting to the Hides gas plant in the Papua New Guinea highlands.
  • Japan’s JERA has purchased the LNG business of France’s EDF Trading, bulking out its energy trading unit in Asia and expanding into Europe.
  • The 65km, US$10 billion pipeline connecting Jordan with Israel’s Leviathan field is now set for completion at the end of 2019.
  • Equinor’s US$954.46 million plan to develop gas reserves in western Troll should support output at the field until about 2060, according to Norway.
  • Sonatrach has raised output at the Alrar gas field near Libya from 16 mcm/d to 24.7 mcm/d, the latest in an output expansion drive at existing fields.
  • Pertamina has decided to axe its planned land-based LNG receiving terminal in Bojonegara, near Jakarta, citing declining domestic gas consumption.

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EIA projects less than a quarter of the world’s electricity generated from coal by 2050

According to the U.S. Energy Information Administration’s (EIA) International Energy Outlook 2019 (IEO2019), global electric power generation from renewable sources will increase more than 20% throughout the projection period (2018–2050), providing almost half of the world’s electricity generation in 2050. In that same period, global coal-fired generation will decrease 13%, representing only 22% of the generation mix in 2050. EIA projects that worldwide electricity generation will grow by 1.8% per year through 2050.

EIA projects that total world electricity generation will reach nearly 45 trillion kilowatthours (kWh) by 2050, almost 20 trillion kWh more than the 2018 level. Although growth occurs in both OECD and non-OECD regions, the growth in electricity demand in non-OECD regions far outpaces those in OECD regions. Even though electricity demand growth contributes to a region’s fuel share of generation, the scale and scope of that region’s policies provide different incentives and play an important role as well.

Throughout the projection period, some regions have high electricity demand growth, some have aggressive emission reduction policies, and some have relatively little change in both. Varying demand growth and policies across regions lead to different distribution of fuel shares for electricity generation within each region. However, the power sector’s share of generation from renewables tends to increase and the share of coal tends to decrease.

High electricity demand growth

net electricity generation by fuel, India

Source: U.S. Energy Information Administration, International Energy Outlook 2019

India has the most rapid regional electricity demand growth (4.6% per year) in the IEO2019 Reference case. Although India has developed target levels for solar and wind capacity, it does not have an aggressive emissions reduction policy in place, so EIA projects coal-fired generation growth in addition to growth in solar and wind generation. Combined, solar, wind, and coal will account for 90% of India's electricity generation mix in 2050. Combined wind and solar generation increases from less than 10% of India's generation mix in 2018 to more than 50% of the generation mix in 2050. The level of coal-fired generation increases during that same time period, but coal’s share of India's electricity generation mix falls from about 75% of the mix in 2018 to less than 40% in 2050.

Aggressive emissions reductions policy

net electricity generation by fuel, OECD Europe

Source: U.S. Energy Information Administration, International Energy Outlook 2019
Note: OECD is the Organization for Economic Cooperation and Development. International Energy Outlook regional definitions.

New capacity additions for renewable technologies are economically competitive with fossil technologies worldwide. But without policy incentives, growth in generation from renewable sources is limited in regions with slow demand growth. OECD Europe electricity demand is projected to grow at about 1% per year through 2050; however, EIA expects that a regional carbon dioxide cap will contribute to a reduction in fossil-fired generation and an increase in renewables generation to meet demand. Throughout the projection period, EIA expects that the share of wind and solar generation in OECD Europe will increase from 20% to almost 50% by 2050. In that same period, EIA projects that fossil-fired generation will decrease from about 37% to 18% of the generation mix. By 2050, coal-fired generation comprises only 5% of the region’s generation mix.

Low electricity demand growth/No emissions reductions policies

net electricity generation by fuel, other non-OECD Europe and Eurasia

Source: U.S. Energy Information Administration, International Energy Outlook 2019
Note: International Energy Outlook regional definitions.

With annual demand growth slower than 1% and no firm policies aimed at reducing carbon dioxide emissions, the mix of generation resources in the non-OECD Europe and Eurasia region (which excludes Russia) will change only marginally. Through 2050, wind and solar generation increases marginally and accounts for less than 10% of the generation mix in 2050, leaving hydroelectric power as the main source of renewables generation for this region. Growth in natural gas generation will displace some coal-fired generation—which falls from 31% in 2018 to 15% in 2050—but the overall share of fossil generation will change relatively little throughout the projection period.

January, 23 2020
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