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Last week in the world oil:

Prices

  • While OPEC looks at ways to improve coordination among its members over the supply freeze, Saudi Arabia has pledged to cut its exports further in August to help reduce the global glut. Crude prices rose in response to this, hitting US$48/b for Brent and US$46/b for WTI, and increasing further as the UAE pledged further output cuts in September and Russia pushes for a 100% compliance with the current global deal.

Upstream & Midstream

  • Deregulation appears to be paying off for Mexico, as Eni announced that its Amoca field contains as much as a billion barrels of oil, joining the massive Zama field discovered last week. The giant new finds confirms that the ‘Mexican side of the Gulf is very prolific’ according to its oil regulator, prompting it to delay its new offshore round by a month to January 2018 to give international bidders more time to evaluate the newly announced assets. The round will also include the first areas from the Cordilleras Mexicanas basin, potentially sparking off a new oil rush.
  • Brazil’s oil regulator is mulling allowing more flexible local content rules to existing E&P contracts in a bid to revive crude projects put on ice in Brazil over low oil prices and tough local content rules, which may restart some key projects, including the subsalt region of the Santos basin.
  • The UK is hoping to capitalise on the recent spurt of activity in its continental shelf, launching an offshore licensing round that focuses on mature areas. Some 813 blocks over a combined area of 114,426 square kilometres in the Southern, Central and Northern North Sea, the West of Shetland and East Irish Sea are open for bidding until November, including some acreage that has not been available since 1965.
  • The US active rig count appears to be reaching saturation point at current price levels, losing two rigs overall last week as drillers held back on activity in an increasingly glutted market.

Downstream

  • Independent US refiner Tesoro, which will become Andeavor in August, has reached a new agreement with Pemex to enter Mexico’s terminal and transportation services sector, enabling access to Pemex’s pipelines and storage terminals in an attempt to break into the retail sector.
  • BP is reportedly considering spinning off some of its US pipeline assets in the Gulf and Midwest in an IPO, structuring them in a Master-Limited Partnership common to American pipeline companies. It is a revival of a plan first considered five years ago, shelved after oil prices crashed. If it goes through, BP will join other refiners like Valero and Marathon, who have created MLPs for their pipeline assets.

Natural Gas and LNG

  • Egypt expects its natural gas output to double by 2020, as the Zohr, North Alexandria and Nooros projects ramp up to ease the country’s current energy deficiency and move it to gas self-sufficiency. Early phases of Nooros and North Alexandria are already in production, increasing output to 5.1 bcf in 2017 from 4.4. bcf in 2016. So much natural gas is expected to come onstream that Egypt is now in talks with its LNG contractors to defer shipments.

Last week in Asian oil

Upstream

  • In an interesting thaw of relations, China’s foreign minister has said that he supports the idea of joint energy ventures with the Philippines in the disputed areas of the South China Sea claimed by both countries. With President Rodrigo Duterte aiming to develop oil fields in the Reed Bank, the overture by China seems to be aimed at diffusing a potential standoff. It could work out to China’s advantage though; if the Philippines agrees to cooperate with China on joint development, it would make future maritime border claims difficult when brought to the International Tribunal for the Law of the Sea.

Downstream

  • As the startup of Nghi Son, Vietnam’s second refinery, approaches – the refinery recently bought its first crude cargo, from Kuwait – the country is looking forward to plans to establish a strategic oil product reserve. It would follow the IEA guidelines to have at least 90 days worth of net imports, aiming to having the storage in place by 2020. Vietnam currently requires its refineries to have 15 days of their processing capacity in crude stockpiles and 10 days in oil products – equivalent to 30-35 days of its current level of net imports. The advent of Nghi Son may bump that up to 60-70 days by the end of the year, with the third refinery still far away.
  • South Korea is looking at easing blending restriction and rules at the country’s large oil storage terminals in the southern ports of Ulsan and Yeosu, as it aims to become a trading hub in Northeast Asia, and potentially challenging Singapore as Asia’s oil trading centre. Easing the blending rules will allow trading companies the leeway to meet client specifications, a key requirement to establishing a trading hub. South Korea’s proximity to China and Japan could definitely support the idea, but there is still a long way to go for Korea to create the necessary physical and financial infrastructure to displace Singapore.

Natural Gas & LNG

  • After what seems like decades of procrastination the Philippines is on the verge on signing on a partner for its US$2 billion LNG receiving and distribution facility. PNOC has shortlisted six countries for six potential partners – China, Japan, South Korea, Singapore, Indonesia and the UAE – which will help construct the facility by 2020, in time to replace the country’s dwindling supplies from the once prolific Malampaya gas field. The facility will likely be in Batangas, as will include new power plant facilities aimed at improving the country’s inconsistent electricity supply.
  • Petronas has delivered its first LNG cargo to Thailand, the first under a 15 year contract that will see the Malaysian state oil firm send up to 1.2 mtpa per year. Running short of natural gas from the domestic sources as well as piped natural gas from Myanmar, Thailand’s PTT has increasingly turned to LNG to meet the country’s growing demand for gas.

Corporate

  • India’s grand ambitions to merge its numerous state oil companies into a giant entity took one step forward with the sale of the state’s 51.1% stake  in HPCL to state upstream company ONGC for US$4.6 billion. This will create the first major India state vertically-integrated company, bringing together the upstream activities of ONGC and the refining and retail network of HPCL, exploiting synergies between the two.

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Your Weekly Update: 14 - 18 October 2019

Market Watch  

Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b

  • Crude oil prices remain stubbornly stuck in their range, despite several key issues that could potentially move the market occurring over the week
  • The sudden thawing of the icy trade relations between the US and China last week – announcing a partial trade deal where new tariffs would be halted – was a positive for the waning health of the global economy; this, however, failed to send prices any higher as previous optimism has always been dashed
  • The trade spat has already caused fears of an economic recession and tumbling global oil demand, with the IEA projecting yet another drop in the demand that has neutralised another possible ‘geopolitical premium’ on prices
  • That geopolitical premium focuses on the fragile situation in the Middle East, with risk spiking up as Iran announced that one of its tankers in the Red Sea – far away from the Persian Gulf - had been struck by missiles; an initial accusation that Saudi Arabia was behind the attack was later withdrawn
  • Meanwhile, news emerged that Nigeria had been quietly handed an increased quota under the OPEC+ supply deal, from 1.685 mmb/d to 1.774 mmb/d, in July, which would help it meet compliance under the deal
  • After more than two months of continuous declines, the US active rig count increased for the first time, but not by much; two oil rigs were added, offset by the loss of a gas rig, but a net gain of 1 to a total of 856
  • We expect prices to remain entrenched as it displays resilience against political and economic factors, with Brent hovering in the US$58-60/b area and WTI at the US$52-54/b range


Headlines of the week

Upstream

  • The US Department of the Interior will be opening up 722,000 acres of federal land along California’s central coast near Fresno, San Benito and Monterey for oil and gas leasing – the first sale in the state since 2013
  • Alongside the lease sale in California, the US will also be opening up some 78 million acres in Gulf of Mexico federal waters for sale in 2020, covering all available unleased areas not subject to Congressional moratorium
  • Santos has confirmed oil flows at the Dorado-3 well in the Bedout Basin offshore Western Australia, with some 11,1000 b/d in place
  • After having exited Norway, ExxonMobil is now reportedly looking into selling its Malaysian offshore upstream assets as part of its divestiture programme, fetching up to US$3 billion for assets including the Tapis Blend operations
  • Equinor has won a new exploration permit – WA-542-P – in the offshore Western Australia Northern Carnarvon Basin, located new the Dorado well
  • Nigeria is looking to settle a US$62 billion income-sharing dispute with international oil firms such as ExxonMobil, Shell, Chevron, Total and Eni operating in the country, with hopes of reaching a settlement
  • Barbados is looking to emulate its nearby neighbour Guyana as it gears up for its third offshore bid round that will launch in early 2020
  • Petroecuador has been forced to declare force majeure on its crude exports, as widespread protests over the removal of fuel subsidies have led to the shutdown of some oilfields
  • Abu Dhabi is looking to create a new benchmark price for Middle Eastern crude based on its Murban grade that could compete with Brent and WTI

Midstream/Downstream

  • Aruba has ended its contract with Citgo – PDVSA’s US refining arm – to operate its 209,000 b/d refinery that is currently idled; a new operator is being sought, paralleling the situation over Curacao’s Isla refinery and PDVSA
  • Poland’s crude pipeline operator expects to only be able to clear its system of contaminated Russian oil from the Druzhba incident by July 2020
  • Gunvor’s Rotterdam refinery will only be able to produce low sulfur fuel oil by March 2020, part of a larger planned overhaul of the 88,000 b/d site

Natural Gas/LNG

  • After Total’s departure, it is now the turn of CNPC to quit the South Pars Phase 11 project in Iran, leaving Iran to go ahead alone its largest natural gas project ever as the threat of US sanctions bites down
  • CNPC has taken over operation of the Chuandongbei sour gas field in China’s Sichuan basin from Chevron, and will kick of Phase 2 development soon
  • Qatar has invited ExxonMobil, Shell, Total, ConocoPhillips and some other ‘big players’ to assist in the North Field expansion that will underpin its ambitions to boost gas output to 110 million tpa from a current 77 million tpa
  • The FID on the Rovuma LNG project in Mozambique has been pushed back by a year, with first production now expected by 2025 at the earliest
  • Pakistan has cancelled a ‘huge’ 10-year tender covering 240 LNG cargoes to its second LNG terminal, turning instead to spot cargoes due to inadequate demand
  • Inpex has formally received a 35-year extension for the PSC covering the Abadi LNG project in Indonesia, extending its operation of the Masela block to 2055
October, 18 2019
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