Last week in the world oil:
-Although trading is thin ahead of Christmas, oil prices have maintained their gains last week, opening the week at the US$52/b levels, as the market anticipate tighter supplies next year, which should end the year on a positive note after a prolonged weakness in prices.
Upstream & Midstream
-The UAE, Kuwait and Oman have joined Saudi Arabia is implementing the planned OPEC cuts, warning some clients on long-term contracts that they would receive reduced supplies of crude from January. Saudi Aramco is also telling a few Asian clients that the cuts would impact them as well.
-Libya’s Sharara and El Feel oil field pipelines have been re-opened, after protestors blocking the assets agreed to halt their action. The oil guards have restarted the long blockaded pipeline, which could restore up to 400 kb/d of output to Libya’s production. Libya’s crude output is one of the two (Nigeria is the other) exempt from the new OPEC supply quotas.
-While other companies are restarted their oil sands projects, Norway’s Statoil is planning a complete exit. It has agreed to sell its Leismer and Corner sites, along with associated midstream assets, to Canada’s Athabasca Oil for C$832 million, which would leave Statoil with no oil sands assets, figuring that the segment will be remain too challenging.
-The US rig count jumped again last week, up by 13, with 12 of those being oil rigs as US producer dilute the OPEC deal by ramping up production.
-Shell will likely sell its 38.5% stake in the 220 kb/d Schwedt refinery in Germany to Varo Energy (a joint venture between Vitol and the private equity Carlyle Group). This deal is part of Shell’s drive to dispose of US$30 billion in assets to pay for its acquisition of the BG Group.
-Petrobras will sell its minority 49% stake in sugar/ethanol company Nova Fronteira Bioenergia to its existing joint venture partner São Martinho for US$133 million in a shares-only payment. The move would hasten Petrobras’ exit from domestic biofuels, but it has indicated that it plans a re-entry once it completes its debt reduction plans. In other Petrobras news, the company has signed a US$5 billion, 10-year financing deal with China Development Bank Corp, as well as agreeing an oil supply accord with China National United Oil, China Zhenhua Oil and Chemchina Petrochemical as its seeks a secure stream of revenue and funding.
Natural Gas & LNG
-Italy’s Eni has sold a 30% stake in its giant Egyptian offshore Zohr gas field to Russia’s Rosneft for US$1.575 billion, after selling a 10% to BP for the same price. Zohr is the largest natural gas find in the Mediterranean thus far, and while Eni is typically good at discovering fields, it lacks the financial clout to pursue its discoveries on its own.
-With CEO Tex Tillerson heading into the US government as Donald Trump’s Secretary of State, ExxonMobil has named heir apparent Darren Woods as the company’s next chairman and CEO. The boss of ExxonMobil’s refining arm since 2012, Woods’ challenge will be to bring his ability to whip refineries into shape to the company’s larger portfolio, including its challenged upstream business.
Last week in Asian oil:
Upstream & Midstream
-Malaysia’s Petronas is finalising the next round of its PanMalaysia transportation and installation contract, which should provide a boon to offshore contractors hurting for business in Asia. The contracts awarded by Petronas cover domestic upstream oil and gas T&I activities for three years, with the previous round in 2014. The bulk of the contracts this time are said to be in the state of Sarawak, as Petronas aims to bulk up its deepwater activities in East Malaysia.
Downstream & Shipping
-China has dealt a blow to its teapot refineries, refusing to renew their fuel export quotas for 2017. This means that any fuel produced by the independent refiners have to be sold within China. This would transform assumptions of the Chinese oil market in 2017, as the teapots were expected to import sizeable amounts of crude. But with outlets now limited to the domestic market and consumption slowing down, this move upends that and we very well see teapot production decline. On the plus side, it may remove the glut of refined products sloshing around Asia, allowing cracks and prices to rise.
-CNOOC’s 200 kb/d Huizhou refinery will start up in May or June 2017, with Saudi Arabia named at the mainly supplier for the plant. CNOOC has traditionally been a more offshore upstream player, but has moved downstream as the traditional lines delineating China’s Big Three energy groups have blurred.
-Indonesia has officially assigned Pertamina to build and operate a planned refinery at Bontang in East Kalimantan. The 300 kb/d project always had to involve Pertamina – it is the state energy company, after all – but this does not mean the project will see fruition; Pertamina does not have the means to undertake a refinery project this big on its own and has faced considerable problems in moving ahead with joint venture partners. Indonesia will also import 500,000 tons of LPG from Iran next year, aimed at plugging a domestic shortage.
-Shell continues its withdrawal from what it considerable peripheral downstream markets, selling its aviation fuel business in Australia to Viva Energy for US$250 million.
Gas & LNG
-Russia’s Novatek, its second biggest gas producer, has signed individual agreements with Japan’s Mitsui, Mitsubishi and Marubeni for co-operation in LNG and energy. The deals will see the companies co-operate in upstream natural gas projects in Russia, including the Arctic LNG-2 project, with Japan hungry to secure LNG supplies while Russia wants to boost its global LNG market share.
-Qatar will merge its two state-owned LNG producers, consolidating Qatargas and RasGas under QatarGas. The move is a reaction to the prolonged slump in oil prices, which has affected LNG given its oil-linked pricing, cutting costs in the town state-run behemoths. Qatargas and RasGas were originally created as separate companies to focus on the Eastern and Western markets, as well as to encourage competition
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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 😊
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.
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.
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.