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Market Watch

Headline crude prices for the week beginning 28 May 2018 – Brent: US$75/b; WTI: US$66/b

  • Oil prices have retreated from their highs, as it becomes evident that OPEC and its NOPEC allies are moving to raise output, to counter potential supply shortfalls from Iran and Venezuela.
  • With fresh sanctions levied on Iran and Venezuela, crude prices had been riding a wave of risk-associated gains, with the market particularly worried about the ongoing ‘implosion’ in Venezuela.
  • With Russia and Saudi Arabia claiming a ‘common position on the future of the oil output cut deal’, both producers have signalled that their taps will open up to ensure a steady supply, calming fears in the market.
  • The new OPEC meeting is on June 22; this was originally supposed to be where OPEC would set out its ‘exit strategy’ from the current production freeze deal, but it seems that attention will be instead focusing on rejigging the numbers to keep prices in their current range.
  • Energy ministers from Saudi Arabia, the UAE and Kuwait will be meeting later this week ahead of the OPEC meeting to discuss a common position.
  • Spooked by OPEC’s move, hedge funds have reduced their net long position in Brent and WTI contracts by over 169 million barrels, sapping the strength in the long-term futures rally
  • The spread between Brent and WTI is now at its largest since 2015, potentially becoming a boon for US producers promoting exports.
  • After a brief pause, US drillers added 15 new oil rigs last week, the largest increase since February, with 859 active oil rigs taking advantage of the current high crude price environment.
  • American oil drillers took a pause in adding new units, with the US oil rig count holding steady last week after six consecutive weeks of gains, where the current total standing is 844 and 4 gains in the Permian offset by losses elsewhere.
  • Crude price outlook: OPEC’s moves may have calmed the market down slightly, but the ongoing issues in Iran and Venezuela are very real and tangible. Prices are unlikely to climb back to US$80/b for Brent, but will stay around US$77-78/b, or US$68-69/b for WTI. 

Headlines of the week

Upstream

  • Shell has made a large and significant deepwater discovery in the US Gulf of Mexico with its Dover well, its sixth in the offshore Norphlet play.  
  • CNOCC is anticipating production at its Kingfisher crude oil fields in Uganda – co-developed with Total – to begin in 2021, with FID in 2018.
  • Peru has cancelled five offshore oil contracts awarded to Tullow Oil, citing insufficient consultations made with coastal residents in the area.
  • Egypt has set October 1 and 8 as deadlines for two major international tenders for oil and gas blocks, which would offer 27 onshore and offshore blocks in a country riding a wave of successful discoveries.

Downstream

  • US refiner Valero and Supply de Mexico has signed long-term agreements to import fuel products from the Corpus Christi and Three Rivers refineries in Texas via pipeline into Nuevo Laredo, northern Mexico.
  • After entering operation in April, Vietnam’s second refinery – Nghi Son – has sold its first batch of diesel, with gasoline sales beginning earlier.
  • Indonesia is reportedly looking for a partner to finish the ongoing upgrade of its Balikpapan refinery in East Kalimantan.
  • Despite facing issues in meeting its current B20 biodiesel mandate, Indonesia is aiming to introduce a new B25 mandate next year.
  • The private 400 kb/d Hengli refinery in Dalian, China, is gearing up for trial operations in October, having purchased 2 million spot barrels of Saudi Arabia Medium crude for delivery in July.
  • The suit by Shell against five former employees of its Singapore refinery is ongoing, with Shell raising the value of fuel products allegedly stolen from its Pulau Bukom refinery to US$40 million.

Natural Gas/LNG

  • Total is taking a 10% stake in the upcoming Novatek-led Arctic LNG-2 project in Russia, with an option to raise its stake by a further 5%.
  • Curadrilla Resources has applied to the UK government to drill the country’s first ever horizontal shale gas well in Lanchashire.
  • ExxonMobil and Total has agreed on the capacity of three LNG trains to be built for PNG LNG, with capacity planned for 2.7 mtpa per train.
  • India’s ONGC is aiming to quadruple output from its offshore Deendayal natural gas block in the Bay of Bengal to some 1 mcf/d by January 2019.
  • BP has agreed to buy 2 mtpa of LNG over 20 years on a FOB basis from Venture Global, which is developing Calcasieu Pass LNG in Louisiana.
  • Rosneft has signed a deal to aid the semi-autonomous Kurdistan region in Iraq to develop its gas resources and build a major gas pipeline.
  • India’s GAIL is reportedly switching focus to short-term and spot deals for its LNG purchases, as a hedge against price volatility.
  • Cheniere has approved construction of a third liquefaction unit at its Corpus Christi LNG terminal, with the first two trains starting in 2019.

Corporate

  • Saudi Aramco’s planned IPO has been delayed to 2019, according to the firm at the St. Petersburg International Economic Forum.
  • Australia’s Santos has rejected a final US$10.8 billion takeover offer from US-based Harbour Energy, which failed in its fifth attempt to buy Santos.

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Natural gas inventories surpass five-year average for the first time in two years

Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.

Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.

When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.

This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.

In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.

The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.

Lower 48 natural gas inventories, difference to five-year average

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report

The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.

By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.

Lower 48 natural gas inventories and Henry Hub futures prices

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)

October, 21 2019
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