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Last Updated: August 7, 2017
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Last Week in World Oil:

Prices

  • Oil prices are showing some health, as US crude supplies seem to be moderating and the threat of renewed sanctions against Venezuela looms after a chaotic election there. Brent and WTI are clustering around the US$50/b mark, which seems to be the new support level, as signs are showing that US production may be shedding some optimism.

Upstream & Midstream

  • Shell has set out a schedule for eight upstream projects due for FID over the next 18 months, as it ramps up upstream investment that has been relatively stagnant since 2015. On the cards are the Bonga South West deepwater FPSO project in Nigeria and the Vito deepwater development in the US. The Val d’Agri onshore oilfield in Italy, Penguins FPSO in the UK and Libra FPSO in Brazil’s pre-salt Santos basin are also listed as potential oil projects. On the gas side, China’s Changbei 2 tight gas project and two LNG projects – Lake Charles in Louisiana and Canada LNG in Kitimat – are also being considered. Shell is looking to spend US$25 billion in 2017 on upstream capex, and a range of US$25-30 billion per year through 2020.
  • Pre-salt offshore production in Brazil has surpassed combined upstream output from all other fields for the first time. Output from Brazil’s pre-salt areas grew by 6.4% to 1.353 mmbpd in June, underpinning a 0.8% jump in production. The Lula field is the main pre-salt production area, at 763,000 bpd on average, with Petrobras remaining Brazil’s largest producer, ahead of Shell and Repsol Sinopec. Expect this trend to continue as Brazil attempts to stimulate investment in pre-salt basins by allowing more in more foreign competition to aid debt-stricken Petrobras.
  • Moderation in US drilling activity continues, with active oil rigs climbing only 2 to 766 last week. Six additional gas rigs were added, bringing the US total to 958, with signs pointing to active rig numbers plateauing as crude oil prices fail to break out from the stubborn US$50/b range.

Natural Gas and LNG

  • Output at Cheniere’s Sabine Pass LNG facility keeps marching upwards, with the company beginning liquefaction at a fourth plant ahead of the schedule. Sabine Pass’ fourth plant was scheduled to begin full service by end-2017, but appears to be starting up early in response to growing demand for Cheniere’s LNG, which is opening up new markets in Europe, Latin America and Asia. Officially commissioning for the fourth plant has yet to be completed, with output aimed at fulfilling a 20-year supply contract with GAIL India. The first three trains at Sabine Pass are contracted to Shell, Spain’s Gas Natural SDG and Korea Gas.
  • France’s highest court has repealed the country’s law on regulated gas, claiming that it flouted EU regulations. This might mean the end of regulated gas pricing in France, which would affect about half of French residential users and 11% of commercial users, weakening the entrenched position of energy group Engie and open up the market to smaller players like Direct Energy and foreign supplier like Italy’s Eni.

Last week in Asian oil

Upstream

  • Petronas has confirmed that it will be exiting Blocks 01 and 02 in Vietnam’s Cuu Long basin once the current PSC ends in early September 2017. Likely linked to declining output at the blocks, which began production in September 1991 as one of the first international ventures in Vietnam, Petronas stresses that the exit does not mean that it is quitting Vietnam, and will remain the operator of Blocks 102 and 106 in the Song Hong basin under Petronas Carigali.
  • China’s CNPC, together with partners Total, Petronas Carigali and Iraq’s South Oil Company, have sanctioned the Phase 3 Halfaya oilfield project in southern Iraq after approving FID. The project will boost production at the Maysan province field from a current 200,000 bpd to 400,000 bpd.
  • After backing joint drilling operations in areas claimed by both China and the Philippines, China is now calling for Vietnam to halt oil drilling in a section of the South China Sea claimed by both Vietnam and China. Drilling at Block 136/3, licensed to Repsol and Mubadala, began in mid-June, with China calling for an immediate halt to activities as it infringes on its territory. This may be posturing by the Chinese government to bring Vietnam to the table for joint oil exploration operations as in the Philippines, but Vietnam is unlikely to acquiesce the way Duterte has, which may lead to inflamed tensions in the South China Sea at a time when US foreign policy under President Trump is unclear.
  • Abu Dhabi’s Adnoc will make a decision on renewing the oil concessions held by Japanese companies in its oilfield by early next year, particularly Inpex’s 12% stake in the massive offshore ADMA block that is set to expire in March 2018. Japanese companies are keen to extend the contracts – key to securing strategic supplies for its refineries – while Abu Dhabi is leaning towards roping in new partners from China and South Korea, as well as expanding the role of majors BP and Total.

Downstream

  • The UAE has bought its first oil cargo from the USA, as it seeks to replace Qatari condensate affected by the current diplomatic row in the Middle East. Qatari supplies to the UAE – used in petrochemical production in the UAE – were halted in June after a Saudi Arabia-led campaign to politically isolate Qatar. Adnoc must now compete with condensate clients in South Korea and Japan to supplies of the ultra-light crude, with condensate from Eagle Ford being the most immediate source.

Natural Gas & LNG

  • Indonesia is aiming to begin constructing on an LNG pipeline system to establish a comprehensive gas distribution network across its vast archipelago. To be undertaken by state firms Pertamina, PGS and PLN, Indonesia will also need to attract international investment for a project that may cost as much as US$48 billion, part of a national plan to boost power generation and energy security in Indonesia.

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Ecuador Exits OPEC

Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.

The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can. 

This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.

The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.

The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis. 

Current OPEC membership:

  • Middle East: Iran, Iraq, Kuwait, Saudi Arabia, UAE
  • Africa: Algeria, Angola, Equatorial Guinea, Gabon, Libya, Nigeria, Republic of Congo
  • Latin America: Venezuela
  • Total: 13
  • Withdrawing: Ecuador (January 2020)
  • Membership under consideration: Sudan (October 2015)
October, 18 2019
U.S. Federal Gulf of Mexico crude oil production to continue to set records through 2020

U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.

Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.

In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.

Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.

anticipated deepwater Federal Gulf of Mexico field starts

Source: Rystad Energy

Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.

Brent crude oil price and U.S. Gulf of Mexico rig count

Source: U.S. Energy Information Administration, Thompson Reuters, Baker Hughes

Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.

October, 17 2019
Crude oil used by U.S. refineries continues to get lighter in most regions

API gravity of U.S. refinery inputs by region

Source: U.S. Energy Information Administration, Monthly Refinery Report

The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.

API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.

The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.

Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.

Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.

lower 48 states production of crude oil by API gravity

Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report

When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.

Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.

By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.

U.S. refinery inputs by region

Source: U.S. Energy Information Administration, Monthly Imports Report and Monthly Refinery Report

East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.

October, 14 2019