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Last Updated: April 13, 2017
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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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The Competition For The LNG Crown

The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.

But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.

Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.

Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes. 

Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.

So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.

There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.

But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊

Market Outlook:

  • Crude price trading range: Brent – US$64-66/b, WTI – US$60-63/b
  • Despite the thaw after Texas saw a devastating big freeze, the slow ramp-up in restoring US Gulf Coast oil production and refining has supported crude oil prices, with Brent moving above the US$65/b level and WTI now in the low US$60/b level
  • Some Wall Street analysts, including Goldman Sachs, are predicting that oil prices could climb above US$70/b level based on current fundamentals, as the short-term spike gives ways to accelerating consumption trends
  • However, much will depend on OPEC+’s approach to managing supply in Q2, with a meeting set for early March; Saudi Arabia is once again urging caution, but there are many other members of the club champing at the bit to increase output and capitalise on the rising price environment


March, 01 2021
EIA forecasts the U.S. will import more petroleum than it exports in 2021 and 2022

Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.

EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.

Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.

U.S. quarterly crude oil production, net trade, and refinery runs

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021

EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.

EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.

February, 18 2021
The Perfect Storm Pushes Crude Oil Prices

In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?

To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.

Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.

That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.

Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.

 

For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.

That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.

Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.

Market Outlook:

  • Crude price trading range: Brent – US$58-61/b, WTI – US$60-63/b
  • Better longer-term prospects for fuels demand over 2021 and a severe winter storm in the southern United States that idled many upstream and downstream facilities sent global crude oil prices to their highest levels since January 2021
  • Falling levels at key oil storage locations worldwide are also contributing to the crude rally, with crude inventories in Cushing falling to a six-month low and reports of drained storage tanks in the US Gulf Coast, the Caribbean and East Asia
February, 17 2021