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Last week in the world oil:

Prices

  • News that a group of non-OPEC producers would join OPEC in implementing a supply cut has jolted oil prices into optimism, rising to US$55/b, with producers hoping it will test the US$60 barrier soon. Mexico, Azerbaijan, Kazakhstan and Oman have joined Russia to agree to implement a 600 kb/d cut, with Russia contributing half of the total.

Upstream & Midstream

  • The rise in oil prices has revived interest in Canadian oil sands, moribund since the price slump. Cenovus Energy and Canadian Natural Resources have announced a go-ahead with their expansion projects, adding 50 kb/d to Christina Lake and 40 kb/d to Kirby North in capacity, respectively.
  • Despite a Brazilian court ordering Petrobras to halt the sale of its fuel distribution subsidiary over labour concerns, the Brazilian state giant says it is pushing ahead with its ambitious divestment program that includes inking some US$4 billion in asset sales this month. The apparent speed at which the deals are taking place has triggered legal concerns that rigging and bribery may have been part of the divestment negotiations.
  • It was to be expected. With prices rising, American producers are capitalising on the expectation of higher prices by restarting rigs. The US rig count jumped by 27 last week, with 21 of those being oil rigs. Last minute drilling to maintain leases may have also contributed to the spike, with the market largely shrugging off the increase.

Downstream

  • Saudi Arabia has begun telling its customers that they will receive reduced crude shipments beginning January, affecting refineries that have long-term contracts with the Kingdom. The curbs are focused on Europe and North America, with Asian refineries largely spared the cull, where Saudi Arabia is battling Iran and Russia for market share.
  • The EUs biofuels push is evolving to reduce dependence on crop-based feeds, aiming to reduce plant-based biofuels from 7% in 2021 to 3.8% in 2030 to assuage concerns of deforestation. Instead, the EU wants to focus on advanced biofuels, involving agriculture and forestry waste.
  • Once a major player in both upstream and downstream, Venezuelas PDVSA is facing trying times. Chronic underinvestment and low oil prices have slashed operating rates at its giant Paraguana, Amuay and Cardon refineries to some 40-45%, while it appears to have been elbowed out of its toll-refining arrangements in Curacao and possibly Aruba. Meanwhile, PDVSA is asking a US court for some US$600 million in compensation from a bribery scheme of two businessmen that bribed PDVSA officials over US$1 billion in supply contracts.

Natural Gas & LNG

  • Anadarko and Eni will now be allowed to sell the Mozambique governments share of gas from their projects in the Rovuma Basin. The countrys government has approved an amendment to its LNG contracts to relinquish its rights to natural gas quotas and gas production tax in an attempt to boost the viability of the projects in the coming era of LNG oversupply. The contracts involved are Anadarkos Dolphin Tuna and Enis South Coral sites, both due for FID next year.

Last week in Asian oil:

Upstream & Midstream

  • Japans state-run JOGMEC has extended its contract with Saudi Aramco to allow the latter to store up to 6.3 million barrels of crude oil in Okinawa for the next three years. Japan allows Saudi Aramco (as well as Abu Dhabis ADNOC) to store crude in Okinawa as a distribution hub for East Asia, in exchange for priority claims on the stock during emergencies.
  • Australias Origin Energy is spinning off its upstream oil and gas unit in an IPO worth at least US$1 billion. The new company, NewCo, has a upstream assets in Australia and the gas market in New Zealand, but will remain smaller than Santos and Woodside, triggering speculation that it could be acquired by an Asian producer, with an eye towards Origins stake in the APLNG plant as it returns to being a gas/power retailer.

Downstream & Shipping

  • Chinas independent teapot refineries are confident that Beijing will keep their 2017 import quotas steady at 2016 level or possibly just a little higher. The teapots were one of the brighter spots in Asia refining this year, sucking up large amounts of crude in the first year they were allowed to directly import crude, and are looking to import more in 2017, a move that would help ease the crude supply glut but contribute to the refined products oversupply in Asia.

Gas & LNG

  • As Papua New Guinea tries to figure out its LNG export strategy, the countrys Prime Minister is now leaning to a single export site, which would require Totals Papua LNG project to export its gas through ExxonMobils existing PNG LNG facility. The merits of having two or a single site have been debated extensively, but concerns over cost are pushing the stakeholders towards having a single large site.
  • The Thai energy policy committee has given its consent to a PTT proposal to acquire LNG from Malaysias Petronas over a 15 year period, beginning with 1 mtpa in 2017 and 2018, then rising to 1.2 mtpa from 2019. Thailand is highly dependent on natural gas for its power infrastructure, and declining domestic production is forcing it to turn to imports.
  • Indonesia has ordered natural gas contractors to cut prices in the fertiliser, steel and petrochemicals sectors beginning January, replacing oil with the more plentiful natural gas to boost economic growth.
  • Malaysias Petronas has inked a deal with Japans Hokuriku Electric Power to supply up to six cargoes of LNG per year to the power provider in northwestern Honshu. The contract will begin March 2018. Petronas is aiming to boost its LNG business, with its PFLNG Satu the first floating LNG unit in the world producing its first cargo last week.

Corporate

  • As part of Beijings attempt to reform the oil and gas industry in China to boost competitiveness, Sinopec has sold a 50% stake in its Sichuan-East China gas pipeline to China Life Insurance and SDIC for some US$6.6 billion. Sinopec will retain a stake in the pipeline, aiming to use proceeds from the sale to expand its other gas pipeline and storage infrastructure. Gas pipeline are increasing in importance in China, with CNPC recently starting up the eastern portion of its third East-West cross-country pipeline, eventually connecting to CNOOCs network in Fujian.

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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