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Last Week in World Oil:

Prices

  • Subdued trading before and after the long Easter weekend led to crude oil prices maintaining a holding pattern around US$55/b for Brent and US$52/b for WTI. With the EIA warning that US shale production was set to rise by its fastest pace in two years, downward pressure on prices will remain, though a surprise fall in US crude stocks last week indicates that demand is relatively robust.

Upstream & Midstream

  • Brazil has outlined its licensing rounds for 2017, 2018 and 2019, with attention on its vast presalt deposits that was once tightly gripped by Petrobras. Focusing on the Santos offshore basin, where 10 of 14 pre-salt fields to be auctioned off over the next two years are located, the three rounds are expected to attract intense attention from supermajors and majors, with estimates suggesting to up to 50 billion barrels of crude could be tapped in the available blocks. Outlining just how the Brazilian upstream industry has opened up, the government is reportedly going to allow Petrobras – which was required by law to own 30% in all blocks and serve as operator - to pull out of the auctions if the price is too high.
  • Despite the long Easter break, the active US oil and gas rig count still managed to add some 8 sites last week. Eleven new oil rigs started up – 8 in the Permian alone – offsetting a loss of 3 gas rigs. The Canadian count continued its decline, losing another 14 sites.

Downstream

  • Not long after the Nigerian government made overtures to legalise some of the illegal refineries operating in the Niger Delta as an attempt to quell uprisings in the area, its military confirmed that it had destroyed 13 bush refineries in the oil-rich region last week. Two soldiers were reportedly killed, but the action will barely put a dent in the illegal activity as there are reportedly hundreds of such makeshift refineries processing stolen crude. Further military action could risk more attacks, which crippled Nigerian crude production for months last year.

Natural Gas and LNG

  • Despite reticence and objection from various EU countries, Russia’s Gazprom seems confidence that its NordStream 2 offshore gas pipeline connecting to Germany will have all the necessary approvals in place for construction to begin in 2018. Poland and Denmark have been among the recent countries to mount objections, over concerns of gas dependence and national security, but Gazprom is moving ahead, contracting Swiss contractor Allseas to undertake offshore pipelay works for the twin pipelines that form the 1,200km system through the Baltic Sea.
  • Gazprom is also moving ahead with securing ultra-long gas contracts, signing a €5.3 billion deal with Slovakia’s Eustream that will link it to the Slovak gas transportation system through 2050. Eustream is the Slovak natural gas transmission system operator, and while it is largely confined to the national grid, terms of the deal may allow Gazprom to leverage on any future connections to other gas systems. 


Last Week in Asian oil:

Upstream & Midstream

  • Timor-Leste has awarded two onshore exploration blocks in an auction that highlights the potential of onshore gas and gas production in the tiny country. Long dependent on its offshore fields, with boundary quarrels with Australia recently settled, the two blocks are split equally between Australia’s Timor Resources Holdings and Timor-Leste’s national oil company Timor Gap. Over 60 oil seeps have been detected in the 2000 square km area that comprises the blocks, with initial indications being highly positive. If tapped, the onshore fields will be the first to be exploited in the country for 40 years.
  • A year after it revived interest in the Ca Rong Do (Red Emperor) field in Vietnam, Spain’s Repsol has raised its stake in the exploration block by 5% to 60%. Acquiring the stake from Australia’s Pan Pacific Petroleum (PPP) for US$5 million, the scale of the field might be small but for Repsol, it represents success in developing its upstream business in Southeast Asia. The field in the Nam Con Son basin is shared with Singapore’s Pearl Energy (25%) and state oil company PetroVietnam (15%).

Downstream & Shipping

  • The long-debated China-Myanmar oil pipeline appears to have made progress after sitting empty for almost two years over political squabbles. First oil is expected to flow this month, delivering crude across the 770km pipeline to a new 260 kb/d refinery in China’s Yunnan province. China views the pipeline as a strategic asset, a complement and an alternative to the Straits of Malacca and Singapore, through which almost all of its crude needs currently flows through. The Myanmar pipeline is a more direct alternative, but will likely never displace the Straits, given that the vast majority of China’s oil infrastructure is coastal.
  • Simmering tensions in North Korea have not prevented life from going on its South Korea, with France’s Total announcing that its joint venture with conglomerate Hanwha will invest US$450 million in their refining and petrochemical projects. The main aim of the expansion will be to expand ethylene capacity by 30% to 1.4 million tons per year, targeted at meeting growing demand from China.

Corporate

  • Petrolimex, Vietnam main state oil importer and distributor, will be going public on the Ho Chi Minh stock exchange, marking the first of Vietnam’s state energy firms to be listed. The government currently owns 76% of Petrolime. It launched its IPO in 2011, but the complicated Vietnamese system meant that shares only began being listed and trading this month, at a price of 43,200 dong (US$1.90) valuing Petrolimex at US$2.46 billion. PetroVietnam is still 100% owned by the state.

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North American crude oil prices are closely, but not perfectly, connected

selected North American crude oil prices

Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.

The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.

Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.

pricing locations of selected North American crudes

Source: U.S. Energy Information Administration

First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.

Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.

Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.

Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.

Principal contributor: Jesse Barnett

May, 28 2020
Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020
From Certain Doom To Cautious Optimism

A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.

Thankfully, it has not.

On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?

The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.

The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.

How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.

The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Demand recovery has underpinned a rally in oil prices, on hopes that the worst of the demand destruction is over
  • Chinese oil demand is back to the 13 mmb/d level, almost on par year-on-year
  • News that development of potential Covid-19 vaccines are reaching testing phase also cheered the market
  • The US active oil and gas rig count lost another 35 rigs to 339, down 648 sites y-o-y

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May, 23 2020