Last week in the world oil:
- Persistently high US crude stockpiles continue to put pressure on global oil prices, overshadowing a high compliance rate within OPEC in meeting the organisation’s agreed cuts. Resurgence in American shale production has kept inventories high as demand flags, raising the possibility that OPEC may have to extend its supply freeze to have any impact.
Upstream & Midstream
- ConocoPhillips has reduced its Canadian oil sand reserves by over a billion barrels, as low global crude prices are forcing it to write down resources previously flagged as recoverable. From 2.4 billion barrels of developed and undeveloped bitumen reserves in Alberta at the end of 2015, the number was revised down to 1.2 billion barrels in the company’s annual financial filings for 2016.
- The active US rig count inched up again by 3 last week, as five additional oil rigs offset a loss of two gas rigs. All gains were on land or in inland waters, with the additions being in the Permian and Eagle Ford basin.
- The UAE’s Adnoc has secured a deal with trader Vitol to supply 528,000 tons of LPG per year over the next 10 years. Beginning January 2017 and lasting through December 2026, it is an attempt to pioneer long-term LPG contracts to deal with an oversupplied market, the additional volumes will likely head to Asia where LPG is fast becoming a new petrochemical feedstock due to the sharp rise in NGL supplies from the US Gulf.
Natural Gas and LNG
- Shell, now the world’s largest LNG trader following its acquisition of the BG Group, has set out its vision for the future of LNG contracts. Instead of multi-decade, mass volume contracts common from the 1980s and 1990s, clients will instead begin to demand shorter, smaller contracts to give themselves flexibility in a competitive market that now favours buyers. Shell also predicts that the bulk of new LNG growth will come from countries aiming to replace declining domestic gas production, like Egypt, Thailand and Pakistan, or where demand is growing strongly, like China.
- The Interconnector Greece-Bulgaria (IGB) natural gas pipeline will begin construction at the beginning of 2018, eventually delivering a billion cubic metres of Azeri gas from the Shah Deniz 2 field to Bulgaria. The project is part of a wider EU vision of a Southern Gas Corridor that will bring gas from the Middle East and Caspian region to reduce dependency on Russia natural gas.
- Under its new CEO, Darren Woods, ExxonMobil looks to continue the supermajor’s stance of promoting energy efficiency and discouraging polluting fossil fuels. Succeeding Rex Tillerson, who led the same stance as CEO before he joined the Trump administration as Secretary of State, Woods has called for a carbon tax to incentivise low-carbon energy solutions for the future. This would put ExxonMobil at odds with the White House, which views a resurgence in fossil fuel exploitation as central to its plan to boost the American economy.
Last week in Asian oil:
Upstream & Midstream
- Iran may be getting in on the shale oil revolution, reporting that it has struck a two billion barrel find in the western province of Lorestan. The area is thought to hold major reserves of shale oil and gas, and the Ghali Koh field discovery confirms it. Iran has rapidly ramped up its crude production levels to pre-sanction levels, and the find signals that it still has room to grow, as it competes with rival Saudi Arabia.
Downstream & Shipping
- After reportedly close to pulling out of the Petronas RAPID refinery project in January, Saudi Aramco is now back on the project. Announced by Malaysian Prime Minister Najib Razak, Aramco will now partner with Petronas on the project as originally planned, investing up to US$7 billion and securing the refinery’s vital crude supply.
- After years of delays, Vietnam’s second refinery – Nghi Son – is finally ready to begin production. First crude oil deliveries are expected at the 200 kb/d site in May, the second of three planned refineries that will serve Vietnam’s south, central and north regions. Nghi Son is designed to process Kuwaiti crude, with Kuwait Petroleum international and Japan’s Idemitsu Kosan being major stakeholders with 35.1%. PetroVietnam, which operates the country’s first refinery Dung Quat, has 25.1%, while Mitsui Chemicals has 4.7% of the integrated refining project.
- Taiwan’s Formosa Plastics Group, hampered at home at its attempts to grow, has applied to the US state of Louisiana to invest up to US$9.4 billion to build petrochemical plants. With the amount of natural gas liquids coming out of the shale revolution, petrochemical feedstock in the US are plentiful (and cheap) at the moment, with Formosa aiming to move production over to the US instead of bringing the NGLs over to Taiwan.
Natural Gas & LNG
- China’s LNG imports rose by nearly 40% in January to 3.44 million tons, providing an opportunity in an oversupplied market. It is the second-highest figure on record behind December 2016, as China imports the fuel for winter heating, and providing hope that continued Chinese demand may lift the slump in LNG prices triggered by fears of a supply overhang.
- Bangladesh will be raising the state-controlled price for natural gas for the second time in under two years. Gas prices will be raised by some 23% in two phases over the year, in March and in June. It is an attempt to reduce the government’s burden over subsidised gas prices. Domestic natural gas is currently sold at half the imported price, and the hike raises fears of inflation across Bangladesh’s critical garment industry, as most of the gas used in the country goes to the power industry.
- Rumours that the Indian government was planning to merge all or most of the state oil firms into an energy titan may have gotten some credence with the announcement that upstream-focused ONGC may be acquiring downstream player HPCL. The deal apparently calls for the Indian government to transfer its majority 51.11% stake in HPCL to ONGC, and the purchase of an additional 26% from shareholders by ONGC, worth US$6.6 billion in total.
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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:
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.
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.
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.
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.
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.
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.