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Last Updated: February 15, 2017
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Business Trends

Last Week in World Oil:


  • Oil traders appear to have moved on from the OPEC production cut, despite its reported effectiveness, to focus on a strengthening US dollar, rising US crude output and Asian buyers sourcing crude from non-OPEC sources. This has sent oil prices back to their previous levels, a holding pattern that hovers around US$53/b for WTI and US$55/b for Brent.

Upstream & Midstream

  • OPEC compliance with its output cut has been reported at 92%, an optimistic figure given the organisation’s history of breaking quotas. More encouragingly, the 11 non-OPEC producers that elected to join the global deal have also lived up to their promise, with a constructive 40% compliance rate of the overall reduction in January as Russia implements the cuts in phases. 
  • Long seen as comfortable within its own borders, state giant Qatar Petroleum (QP) is now exploring overseas options. The largest LNG producer in the world will also be trimming domestic costs by merging Qatargas and RasGas, while pursuing upstream assets in Morocco and Cyprus, where it recently won a bid for 40% of an exploration plot.
  • The active US oil and gas rig count is now 80% higher than its recent lowest point in May 2016, with eight new oil rigs joining four gas rigs to bring the total count to 591 for oil rigs and 741 for the overall count.


  • London-listed Irish conglomerate DCC has agreed to purchase ExxonMobil’s fuel retail network in Norway for a reported NKR2.43 billion (US$294 million). It is the latest pullout by a supermajor from the mature European fuel retail market, with the 142 company-operated Norwegian sites now joining DCC’s European fuel retail network.

Natural Gas and LNG

  • Petrobras’ attempt sale of a natural gas distribution unit to Brookfield Asset Managament for US$5.2 billion has hit a snag, the latest legal snafu to set back the Brazilian oil giant’s attempt to restore financial health through asset sales. A federal judge in Brazil has blocked the sale of Nova Transportadora do Sudesteon on the grounds that the sale was not sufficiently publicised, raising concerns that the asset sales was being rushed through without fostering competitive bids. A separate regional court has also suspended Petrobras’ planned divestment of two offshore gas fields to Karoon Gas Australia.


  • France’s Total has outperformed most other supermajors in 2016, announcing adjusted net profit of US$8.2 billion, above Shell (US$7.2 billion), BP (US$2.6 billion) and Chevron (US$1.8 billion), behind only ExxonMobil (US$8.9 billion). Its 4Q16 net profit beat analyst expectations at US$2.4 billion, and Total is planning to buck the supermajor trend by hunting for upstream and downstream assets put on sale by its rivals.

Last Week in Asian Oil:

Upstream & Midstream

  • Crude is coming into Asia and into China from all over the world now, from places that do not normally send crude here. Husky Energy just recorded the first sale of its Atlantic Canada crude to China last week, sending a million barrels from the White Rose field to China, instead of its usual destinations in the US and Europe. The trade became possible because of the OPEC supply cut, that led to cuts in deliveries to Asian buyers, but also because of the unusually low shipping rates that are now opening up uncommon trades and shipping routes as beleaguered shippers clamour for business.

Downstream & Shipping

  • Saudi Aramco has inked an agreement with Chinese oil refiner North Huajin Chemical Industries Group to supply crude to its 150 kb/d refinery. Primarily aimed at producing naphtha for petrochemical production, the steady flow of Arab Extra Light is Saudi Aramco’s attempt to regain its status as the top crude supplier to China, after coming in second to Russia in 2016. Huajin is a unit of China’s military group NORINCO and while it is not an independent Chinese teapot, it is a new customer for Saudi Aramco as the latter makes its push to seek new Chinese buyers by offering spot cargoes and competitive credit terms.

Natural Gas & LNG

  • The Singapore Exchange (SGX) and broker Tullett Prebon are developing a new LNG spot pricing index, joining its existing Singapore and Northeast LNG Sling indexes. The new Sling Index focuses on west Asia, known as the Dubai-Kuwait-India (DKI) Sling that will be published every Monday and Thursday covering spot prices between the Middle East and India. The new index should launch in the second quarter of 2017, standardising LNG pricing in Asia and positioning Singapore as the region’s trading hub.
  • Indonesia is facing a glut of LNG this year, with a reported 63 uncommitted cargoes of the fuel between the Tangguh and Bontang projects, according to the Director General of Oil and Gas. At current bookings, Bontang will have 32 uncommitted LNG cargoes and Tangguh 31, and there may be more in 2018 with the expansion of Tangguh being sanctioned. LNG cargoes are generally locked up in long-term contracts, with uncommitted cargoes sold on the prompt market at spot prices.
  • South Korea’s Kogas has expressed interest in buying into US shale gas projects, aiming for supply security, as US-South Korean trade relations head for rockier times under the Trump administration. Kogas is the world’s second largest buyer of LNG, receiving its first US LNG cargo from Cheniere this year. But rather than be a mere buyer, Kogas is following the example of Japanese gas companies by becoming asset owners as well, hedging against rockier political times.


  • A surprise shakeup has happened at Pertamina. CEO Dwi Soetjipto and Deputy CEO Ahmad Bambang have been removed from their positions by the Pertamina Board of Commissioners and the Ministry of State-owned entreprises. With Yenni Andayani (the former new and renewable energy director) as acting CEO, the changes are reportedly to ‘refresh’ the company structure as the ‘complex recruitment and management structure has obstructed cooperation.’ Pertamina chairman Tanri Abeng denied that the removals were linked a corruption case. The company aims to introduce a new streamlined corporate structure and new CEO by the beginning of March.

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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
EIA expects record liquid fuels inventory builds in early 2020, followed by draws

quarterly global liquid fuels productionand consumption balance

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity.

After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years.

As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).

changes in quarterly global petroleum liquids consumption

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases.

Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing.

EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.

EIA expects OPEC production will begin increasing in July 2020 in response to rising global oil demand and prices. From that point, EIA expects a gradual increase in OPEC crude oil production through the remainder of the forecast and for production to rise to an average of 28.5 million b/d during the second half of 2021.

changes in quarterly global petroleum liquids production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), May 2020

EIA forecasts the supply of non-OPEC petroleum and other liquid fuels will decline by 2.4 million b/d in 2020 compared with 2019. The steep decline reflects lower forecast oil prices in the second quarter as well as the newly implemented production cuts from non-OPEC participants in the OPEC+ agreement. EIA expects the largest non-OPEC production declines in 2020 to occur in Russia, the United States, and Canada.

May, 20 2020
Large battery systems are often paired with renewable energy power plants

Pairing renewable energy generators with energy storage, particularly batteries, is increasingly common as the cost of energy storage continues to decrease. The U.S. Energy Information Administration’s (EIA) latest inventory of electric generators shows that the number of solar and wind generation sites co-located with batteries has grown from 19 paired sites in 2016 to 53 paired sites in 2019. This trend is expected to continue: according to planned installations reported to EIA, another 56 facilities pairing renewable energy and battery storage will come online by the end of 2023.

applications served by utility-scale batteries at renewable plus storage facilities

Source: U.S. Energy Information Administration, Annual Electric Generator Report
Note: Many battery systems provide more than one application.

Combining energy storage with renewable technologies such as wind and solar provides a variety of benefits. One of the most critical is the ability to store energy as it is generated and then redistribute it when needed, rather than as it is produced. This ability reduces the need to curtail renewable generation and allows the energy to be deployed during periods of high electricity demand.

Although the most commonly reported application for batteries co-located with renewable sources is storing excess energy, the majority of batteries serve more than one function. Frequency regulation, which helps maintain the grid’s electric frequency on a second-to-second basis, is the second-most common use for batteries co-located with renewables. Batteries can also provide transmission and distribution support, helping to smooth out energy flows. The ability to support the integration of renewables into the grid’s current infrastructure, in addition to other ancillary services that they perform such as frequency regulation, are primary drivers in the growth of battery-renewable pairings.

operating and planned renewable plus storage capacity for top 10 states

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory

Currently, more than 90% of the total operating hybrid (renewable generator plus energy storage) capacity in the country is located in just nine states. Texas alone has 46% of the current total. Hybrid capacity in the United States is concentrated at a few large sites, and 10 facilities account for more than half of total operational capacity. Installation as part of a hybrid system is common for batteries but not for renewable generators such as wind and solar. Although nearly 25% of total U.S. battery capacity is installed as part of a hybrid system, only 1% of total wind capacity and 2% of total solar capacity is part of a hybrid system.

Reported data show that future projects will be much larger in scale than currently operating projects. One anticipated projected in Nevada called Gemini Solar is expected to add more than one gigawatt of combined renewable and storage capacity. The U.S. Department of the Interior approved the Gemini Solar project on May 11, 2020, and the first phase of construction is expected to begin in 2021. By the end of 2023, average renewable capacity at proposed U.S. facilities will more than double from 34 megawatts (MW) to 75 MW, and average battery capacity will grow from 5 MW to 36 MW.

May, 19 2020