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Last Week in World Oil:

Prices

  • America missile strikes launch against Syria sparked a jump in crude oil prices last week, an upward momentum that has continued into this week as Libya’s Sharara oil field stopped production on Sunday over a blocked pipeline and Saudi Arabia signalled to OPEC to it would like to maintain output cuts for another six months. Brent is now trading at US$56/b, and WTI at US$53/b, the highest range in two months.  

Upstream & Midstream

  • BP has sold its Forties Pipeline System (FPS) and the Kinneil Terminal in Grangemouth to Ineos for US$250 million, transferring over the last major Forties asset in BP’s hand. Stating that BP’s interests are now centred among the ‘major offshore interests west of Shetland and in the Central North Sea’, Ineos will now control a strategic asset responsible for some 40% of North Sea production, and constituent component of the Brent crude benchmark. The nearly 400km Forties pipeline system links 85 North Sea output sites back to the UK mainland in Grangemouth.
  • Nexen and ConocoPhillips have both been forced to reduce output at their Alberta oil sands sites due to a shortage of synthetic crude. Necessary because the heavy bitumen is unable to flow through pipelines, a recent fire at the 350 kb/d SynCrude plant has reduce output to zero in April. This has led ConocoPhillips to reduce production at its 140 kb/d Surmont project by 40% and Nexen at its 40 kb/d Long Lake site. 
  • Fifteen additional oil (10) and gas (5) rigs entered service in the USA bringing the total up to 839, with the most gains being in the Permian Basin, again. Canadian rigs, however, continue their slide, losing 23 sites. 

Downstream

  • Nigeria is aiming to legalise the illicit oil refineries that operates in its restive Niger Delta region, part of a wider attempt to quell separatist sentiments in the production heartland. Known as bush refineries, the simple topping structures refine crude stolen from oil company pipelines. By aiming to legalise the refineries, Nigeria hopes to prevent the communities that tend to their sites from being radicalised into military groups and instead be absorbed into the official economy. 

Natural Gas and LNG

  • Gazprom has applied for permission from Denmark to build part of its Nord Stream 2 pipeline through Danish waters, prompting the government is considering new legislation that will allow it to ban such projects over ‘foreign and security grounds’. The contentious pipeline has been accused by some EU countries as allowing them to be ‘hostages to Moscow’, but the wider EU Commission supports the project. 
  • Independent Oil & Gas (IOG) has acquired the disused North Sea Thames Game Pipeline from Perenco UK, Tullow Oil and Centrica, as it seeks to exploit its Blythe and Vulcan hubs. The pipeline system exchanged hands for a ‘nominal consideration’, and IOG plans to use it to deliver up to 500 bcf of natural gas to the Bacton Gas Terminal over a 15-20 year period.
  • The EU and Israel are aiming to construct a 2,000km trans-Mediterranean gas pipeline by 2025 to move natural gas from coastal Israel and Cyprus to gas-hungry European markets like Greece and Italy, as well as beyond. 


Last Week in Asian Oil:

Upstream & Midstream

  • Iran has dismissed India’s threat to slash crude imports by 20% unless Iran anoints an India consortium operator of the giant Farzad B gas field. Stating that it ‘cannot sign a contract under threat’, Iran’s oil minister said that India’s current offers for the gas field development are not acceptable, even after extension of deadlines. Long dependent on India for crude sales during the era of American-led sanctions, Iran has grown bolder since the sanctions were lifted, dismissing the threat from its ‘good costumer’ as it now has many more buyers to trade with. 
  • Even as ExxonMobil pushes ahead with its Papua New Guinea LNG export plans, it is assessing a giant new field that could add between 1-3 tcf of gas to its PNG operations. The Muruk field was discovered in the onshore North Highlands in December 2016 by a consortium of EXM, Oil Search and Barracuda, and test drills have been ongoing. A second sidetrack was sanctioned last week, to define the structure of the reservoir, as results continue to be encouraging. 
  • Iraq’s state oil marketer SOMO and Litasco, the trading arm of Russia’s Lukoil, have formed a joint crude marketing venture, that would assist Iraq is marketing its crude in Russia and Asia, as well as provide training.

Downstream & Shipping

  • ExxonMobil is in official talks to acquire Singapore’s Jurong Aromatics Corporation (JAC), a move that would boost its fuel and petrochemicals production in Asia. The beleaguered JAC was meant to be a shining new asset contributing to Asia’s hunger for petrochemicals when it started up in 2014, but the global commodities route and technical issues forced it into receivership in September 2015. Currently producing under toll agreements with Glencore and BP, the acquisition would boost ExxonMobil’s paraxylene capacity in Singapore by 800,000 tons and add an additional 2.5 million tons per year of oil products. 
  • Fresh from its downstream retail ventures in Mexico and India, BP is now aiming to crack another fuel retail market with great potential that is slowly opening up: Indonesia. The supermajor has inked an agreement with AKR Corporindo, one of only two players allowed to sell subsidised fuels in Indonesia, forming a new company – PT Aneka Petroindo Raya – that will open its first retail site by 2018. The venture is unlikely to be able to crack the subsidised fuel market, but will most likely focus on affluent areas in Java as a ‘differentiated’ retail business. 

Natural Gas & LNG

  • Even as Japanese LNG buyers seek to modify contracts to their liking given the current buyers’ market, they are reacting with caution to a new, bold pricing scheme offered by Tellurian. The American player is seeking to sell its US LNG cargos at a delivered fixed price of US$8 mmBtu from 2023 onwards, breaking with decades of tradition where LNG was sold at fixed volume contracts linked to oil prices. JERA expressed interest in the offer, which is competitive even at today’s depressed spot LNG prices, but mentioned that ‘fixed prices are a gamble.’ 

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EIA forecasts world crude oil prices to rise gradually, averaging $65 per barrel in 2020

monthly Brent and WTI crude prices

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2019

EIA’s January Short-Term Energy Outlook forecasts that world benchmark Brent crude oil will average $61 per barrel (b) in 2019 and $65/b in 2020, an increase from the end of 2018, but overall it will remain lower than the 2018 average of $71/b. U.S. benchmark West Texas Intermediate (WTI) crude oil prices were $8/b lower than Brent prices in December 2018, and EIA expects this difference to narrow to $4/b in the fourth quarter of 2019 and throughout 2020.

EIA expects U.S. regular retail gasoline prices to follow changes to the cost of crude oil, dipping from an average of $2.73/gallon in 2018 to $2.47/gallon in 2019, before rising to $2.62/gallon in 2020. Because each barrel of crude oil holds 42 gallons, a $1-per-barrel change in the price of crude oil generally translates to about a 2.4-cent-per-gallon change in the price of petroleum products such as gasoline, all else being equal.

EIA estimates that global petroleum and other liquid fuels inventories grew by an average rate of 0.4 million barrels per day (b/d) in 2018 and by an estimated 1.0 million b/d in the fourth quarter of 2018. EIA expects growth in liquid fuels production in the United States and in other countries not part of the Organization of the Petroleum Exporting Countries (OPEC) will contribute to global oil inventory growth rates of 0.2 million b/d in 2019 and 0.4 million b/d in 2020.

Although EIA forecasts that oil prices will remain lower than during most of 2018, the forecast includes some increase in prices from December 2018 levels in early 2019 in order to keep up with demand growth and support the increased need for global oil inventories to maintain five-year average levels of demand cover. EIA expects crude oil prices to continue to increase in late 2019 and early 2020 because of an increase in refinery demand for light-sweet crude oil, which is the result of regulations from the International Maritime Organization that will limit the sulfur content in marine fuels used by ocean-going vessels.

world liquid fuels production and consumption balances

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2019

EIA expects global oil production growth in 2019 to be led by countries that are not part of OPEC, particularly the United States. EIA expects non-OPEC producers will increase oil supply by 2.4 million b/d in 2019 which will offset forecast supply declines from OPEC members, resulting in an average of 1.4 million b/d in total global supply growth in 2019.

In 2020, EIA expects oil production to increase by 1.7 million b/d because of production growth in the United States, Canada, Brazil, and Russia, while overall OPEC crude oil production is expected to remain flat. EIA forecasts global oil demand to grow by 1.5 million b/d in 2019 and in 2020. In both 2019 and 2020, China is the leading contributor to global oil demand growth.

January, 17 2019
Your Weekly Update: 7 - 11 January 2019

Market Watch

Headline crude prices for the week beginning 7 January 2019 – Brent: US$57/b; WTI: US$49/b

  • Crude oil looks set to climb back to previous support levels as OPEC’s new supply deal kicks in and the US Federal Reserve sought to soothe investor confidence after initiating a surprise hike in interest rates that caused widespread global financial panic in December
  • Even as OPEC+ moves forwards with a planned 1.2 mmb/d cut in collective output, production across OPEC had already fallen over November and December as Saudi Arabia throttled production to support falling prices
  • Together with dwindling production in Venezuela, disruptions in Libya and losses in Iran, oil output from OPEC countries has already fallen by 530,000 b/d in December to 32.6 mmb/d, the sharpest pullback since January 2017
  • This has managed to re-assure the market that the global supply/demand balance is on firmer footing, even as Russian oil output reached a post-Soviet high of 11.16 mmb/d, just slightly off the all-time record of 11.42 mmb/d in 1987
  • With the recovery in prices, planned upstream projects will be back on firmer footing, with Rystad Energy expecting some US$123 billion of offshore projects to be sanctioned over 2019 if Brent crude averages US$60/b
  • Also supporting the upward momentum is the removal of 8 oil rigs from the active US rig count, as American drillers weighed up the risks of the fragile trajectory in WTI prices
  • Crude price outlook: Momentum is with crude oil prices this week, and we expect that to continue as OPEC+ implements its production plan, with Brent recovering to US$60-62/b and WTI to US$51-53/b


Headlines of the week

Upstream

  • Eni has acquired the remaining 70% of the Oooguruk field in Alaska from Caelus Natural Resources, bringing its stake to 100% to synergise with the nearby Nikaitchuq field, where Eni also owns a 100% interest interest
  • The deepwater Egina field in Nigeria, operated by Total through an FPSO, has started up production, with peak output expected at 200,000 b/d
  • Commercial production of crude at PAO Novatek/Gazprom’s Yaro-Yakhinskoye field has commenced, with output expected at 24,000 b/d
  • Total has sold a 2% interest in Oman’s Block 53 to Sweden’s Tethys Oil, bringing it into Occidental Petroleum’s 100,000 b/d Mukhaizna field
  • Brazil is preparing for its sixth round of upstream auctions, offering up pre-salt acreage in five areas expected to raise more than US$2 billion in sales
  • After recently making its 10th discovery in Guyana, ExxonMobil has its sights set on more as it drills two more exploration wells – Haimara-1 and Tilapia-1 – in the prolific Stabroek block, both close to existing discoveries
  • Ecuador is initiating a probe into some US$4.9 billion worth of oil-related infrastructure projects initiated by the previous administration on charges of corruption and looting

Downstream

  • China appears to be tempering crude demand, with the first batch of crude oil import quotas issued to state and private refineries at 26% lower than 2018, with quotas for teapots at some 78% of the 89.84 million tons approved
  • Saudi Aramco has acquired complete ownership of German specialty chemicals producers Lanxess AG by acquisition Dutch firm Arlanxeo’s 50% stake at €1.5 billion, strengthening its foray into petrochemicals
  • Iran will be investing some US$212 million into Chennai Petroleum’s 180 kb/d expansion of the Nagapatinam refinery on India’s east coast, as Iran looks for ways to ensure captive demand for its crude in one of its largest markets
  • The Mariner East 2 NGLs pipeline – transporting ethane, propane and butane over 560km to the Marcus Hook processing plant in Pennsylvania – has been completed, with the Mariner East 2X pipeline schedules for late 2019

Natural Gas/LNG

  • Shell’s 3.6 mtpa Prelude FLNG has finally started up initial production, the last of Australia’s giant natural gas projects to be completed
  • Brunei Shell Petroleum (BSP) has completed the onshore Darat Gas Project in Lumut, expanding LNG capacity in Brunei by 5% at the Rasau station
  • ExxonMobil’s Rovuma LNG project in Mozambique will be aiming to sanction FID in 2019 for its first phase, involving two trains with a combined capacity of 7.6 million tpa from the offshore Area 4 block
  • As LNG developments in Papua New Guinea move quickly to commercialisation, the PNG government has passed new laws to impose a domestic gas requirement and other provisions for new gas projects, to ensure adequate supply of resources for growing local demand
January, 11 2019
The Prospects of Venezuelan Oil

At some point in 2019, crude production in Venezuela will dip below the 1 mmb/d level. It might already have occurred; estimated output was 1.15 mmb/d in November and the country’s downward trajectory for 2018 would put December numbers at about 1.06 mmb/d. Financial sanctions imposed on the country by the US, coupled with years of fiscal mismanagement have triggered an economic and humanitarian meltdown, where inflation has at times hit 1,400,000% and forced an abandonment of the ‘old’ bolivar for a ‘new bolivar’. PDVSA – once an oil industry crown jewel – has been hammered, from its cargoes being seized by ConocoPhillips for debts owed to the loss of the Curacao refinery and its prized Citgo refineries in the US.

The year 2019 will not see a repair of this chronic issue. Crude production in Venezuela will continue to slide. Once Latin America’s largest oil exporter – with peak production of 3.3 mmb/d and exports of 2.3 mmb/d in 1999 – it has now been eclipsed by Brazil and eventually tiny Guyana, where ExxonMobil has made massive discoveries. Even more pain is on the way, as the Trump administration prepares new sanctions as Nicolas Maduro begins his second term after a widely-derided election. But what is pain for Venezuela is gain for OPEC; the slack that its declining volumes provides makes it easier to maintain aggregate supply levels aimed at shoring up global oil prices.

It isn’t that Venezuela doesn’t want to increase – or at least maintain its production levels. It is that PDVSA isn’t capable of doing so alone, and has lost many deep-pocketed international ‘friends’ that were once instrumental to its success. The nationalisation of the oil industry in 2007 alienated supermajors like Chevron, Total and BP, and led to ConocoPhillips and ExxonMobil suing the Venezuelan government. Arbitration in 2014 saw that amount reduced, but even that has not been paid; ConocoPhillips took the extraordinary step of seizing PDVSA cargoes at sea and its Caribbean assets in lieu of the US$2 billion arbitration award. Burnt by the legacies of Hugo Chavez and now Nicolas Maduro, these majors won’t be coming back – forcing Venezuela to turn to second-tier companies and foreign aid to extract more volumes. Last week, Venezuela signed an agreement with the newly-formed US-based Erepla Services to boost production at the Tia Juana, Rosa Mediano and Ayacucho 5 fields. In return, Erepla will receive half the oil produced – generous terms that still weren’t enough to entice service giants like Schlumberger and Halliburton.

Venezuela is also tapping into Russian, Chinese and Indian aid to boost output, essentially selling off key assets for necessary cash and expertise. This could be a temporary band-aid, but nothing more. Most of Venezuela’s oil reserves come from the extra-heavy reserves in the Orinoco Belt, where an estimated 1.2 trillion barrels lies. Extracting this will be extremely expensive and possibly commercially uneconomical  – given the refining industry’s move away from heavy grades to middle distillates. There are also very few refineries in the world that can process such heavy crude, and Venezuela is in no position to make additional demands from them. In a world where PDVSA has fewer and fewer friends, recovery will be extremely tough and extremely far-off.  

Infographic: Venezuelan crude production:

  • 2015: 2.7 mmb/d (output), 1.9 mmb/d (exports)
  • 2016: 2.6 mmb/d (output), 1.8 mmb/d (exports)
  • 2017: 2.1 mmb/d (output), 1.5 mmb/d (exports)
  • 2018: 1.3 mmb/d (output), 1.2 mmb/d (exports)
  • November 2018: 1.15 mmb/d (output), 1.05 mmb/d (exports)
January, 10 2019