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Last Updated: March 15, 2017
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Last Week in World Oil:

Prices

  • With US drilling rising and crude inventories soaring, WTI crude oil has slipped underneath the US$50/b psychological barrier, with Brent not far behind at US$51/b. Some OPEC producers already calling for an extension of the six-month output freeze, but all that will do is stabilise prices.

Upstream & Midstream

  • Shell will be withdrawing almost entirely from Canadian oil sands, an acknowledgement that expensive projects are non-starters in the current price environment. It will sell its existing and undeveloped oil sands interest to Canadian Natural for US$8.5 billion – going a long way to reducing its debt from acquiring BG – and will also reduce its share in the Athabasca Oil Sand Project from 60% to 10%. The net gain for Shell will be US$7.25 billion, as it has also purchased half of Marathon Oil Canada.
  • In other Shell news, the supermajor is reluctant to reopen the Trans Forcados pipeline in Nigeria, leaving the 400 kb/d Forcados export terminal idle, fearing new attacks by militants. Though attacks by the Niger Delta Avengers have lessened, Shell is demanding additional protection from a government desperate to bring nearly 500 kb/d of offline capacity back. The pipeline was bombed twice last year, the second time just 48 hours after seven months of repairs were completed.
  • Eight new oil rigs were activated last week, joining five new gas rigs to bring the US active rig count to 768, the eight consecutive weekly rise.

Downstream

  • The liberalisation of the Mexican fuel retail industry, breaking the Pemex monopoly and introducing price reforms, has downstream companies buzzing. The biggest of these is BP, which is planning to open up some 1,500 service stations over the next five years, another sign that the British supermajor may be warming back to the idea of downstream retailing after years of focusing on upstream. And it isn’t the only big player interested; trader Glencore is also mulling a move into Mexican retail, investing over US$200 million in a 15-year supply deal.
  • Austria’s OMV is selling its Turkish fuel supply and distribution unit Petro Ofisi to Vitol for US$1.45 billion, as it moves to shed non-core assets, particularly in the low-margin Turkish market. Current political tensions between Turkey and the EU may have also contributed to the sale.

Natural Gas and LNG

  • Russia’s Gazprom has announced a round of delays for its LNG projects, pushing the Sakhalin-2 project from 2021 to 2023/4, and the Baltic LNG plant in Leningrad from 2021 to 2022/3. The delays could leave Russia behind Canada, Australia and the US in the race to supply LNG-hungry Asia, and behind its target to triple its current market share by 2035.

Corporate

  • As Saudi Aramco tidies up its vast holdings – including its split with Shell over the Motiva Enterprises venture in the US – fund managers and institutional investors are expecting it to achieve a market capitalisation of up to US$1.5 trillion in its planned IPO, which would instantly make it the most valuable public company in the world.


Last Week in Asian Oil:

Upstream & Midstream

  • The sale of Chevron’s Bangladesh natural gas assets may be attracting  friction between the government and China. After a request to hike gas prices failed in 2015, the US supermajor put its assets – which account for roughly 60% of Bangladesh’s production from the onshore Bibiyana, Jalalabad and Moulavi Bazar fields – up for sale and cancelled a planned US$650 million investment. State-owned Petrobangla has first refusal, but China’s Zenhua Oil is also in the running, pricing the assets at about US$2 billion. Zhenhua is an arm of China’s NORINCO, a state-run defence industry player, and is one of the minor energy players stepping out of the Sinopec and PetroChina shadows to assert China’s influence globally.
  • Myanmar has given the go-ahead on the MD-7 project, which will see French major Total purchase a 50% interest in the offshore deepwater block from Thailand’s PTTEP. PTTEP has traditionally been the major upstream player in Myanmar, a holdover from the days when the country was considered a pariah nation, and has an on-going collaboration with Total that stretches back 30 years.  
  • Spain’s Repsol sold its 50% interest in the Indonesian Ogan Komering PSC (Production Sharing Contract) to local player Jadestone Energy. The tiny South Sumatran block, producing an average of 3 kb/d, is seen by Jadestone as key in expanding its Indonesia presence. Pertamina retains the other 50%, with Repsol seemingly more interested in the discovery it made in Alaska’s North Slope, the largest conventional onshore discovery in the US for over 30 years.

Downstream & Shipping

  • Two months after a setting a monthly crude import record, February 2017 crude imports reached China’s second-highest level, despite the shorter month. Volumes entering China rose to 8.286 mmb/d, with the demand from independent teapots driving the rise. Imports should ease over the next few months, as some major refineries enter maintenance periods, but the strong teapot demand may keep imports high.

Natural Gas & LNG

  • Malaysia’s Petronas has inked a new LNG deal, the third signed so far this year with the client once again being Japanese. The contract will send some 130,000 tons of LNG per year to the Hokkaido Electric Power Company over a 10 years, supplied from the Bintulu LNG complex.
  • BP’s Tangguh Train 2 in Indonesia’s West Papua will be shut down for nearly two months beginning early April. The routine maintenance should not affect the Tangguh LNG’s production plan for the year, which include 63 uncommitted cargoes. Tangguh Train 1 will remain operational.

Corporate

  • There might be a new name in China to watch. With ambitions of becoming the‘second Sinopec’, private Chinese conglomerate CEFC China Energy has already bought a 4% stake in an Abu Dhabi oilfield for US$900 million and has approached several large independent teapots in Shandong with an idea to acquire its first domestic refinery operation. It is the first example of a large private firm attempting to break into the ranks of Chinese energy majors, a motivation encouraged by Beijing as it seeks to foster competition in the domestic market. CEFC already owns a refinery in Romania, a network of service stations in Europe and an oilfield in Chad, all acquired on the quiet in just two years.

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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
The State of Industry: Q4 2020 Financials – A Fragile Recovery

Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.

That didn’t happen.

Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.

Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.

If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.

On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.

The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.

The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.

Market Outlook:

  • Crude price trading range: Brent – US$60-62/b, WTI – US$57-59/b
  • The Brent crude benchmark rose above US$60/b level for the first time in over a year, as the demand outlook for fuels improves with the accelerating rollout of Covid-19 vaccines and tight stockpiles brush off worries of oversupply
  • On the latter, the IEA estimated that global stockpiles of crude and fuels in onshore and floating storage has shrunk by 300 million barrels since OPEC+ first embarked on its deep production controls in May; in China, stockpiles are at their lowest level over a 12-month period, with US crude stockpiles also fell by 1 million barrels
  • Despite a tenuous alliance, OPEC+ has continuously reassured the market that it will work to clear the massive oil surplus created by the pandemic-induced demand slump, signalling that despite its internal differences, a repeat of last March’s surprise price war is not on the cards

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February, 10 2021