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Last Updated: March 8, 2017
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Last week in World Oil:

Prices

  • Global crude prices remain firmly in their existing range, with Brent starting the week around US$56/b and WTI at US$53/b. Rising US production and signs that buyers are seeking alternate supplies have capped any gains made from the OPEC production cut, with the Iraqi oil minister publicly stating that he believes the cuts may have to be extended to the end of the year to support the current price environment.

Upstream & Midstream

  • Iran’s northern city of Kirkuk continues to be an incendiary environment. After four bombs hit a pipeline connecting the Bai Hassan oilfield to the degassing station – thought to be the world of Islamic State militants – additional disruption came when Kurdish forces seized a processing site, threatening to hold it hostage until the national Iraqi government to building a refinery in a region that wants additional autonomy.
  • Another week and another rise, though the rate of expansion is slowing down. This is the seventh consecutive rise in the weekly US active site count, with seven new gains in oil outweighing a loss of five gas rigs.

Downstream

  • South American nation Guyana has struck oil. With ExxonMobil and its partners discovering between 800 million to 1.4 billion barrels of oil offshore Guyana and production expected in 2020, the next question is what to do with the oil. Guyana does not currently have any refinery facilities, and the government is now mulling striking an agreement with neighbours Trinidad and Tobago, a Caribbean refinery centre, to ship its crude there for third-party processing. Suriname, which also has an underperforming refinery, has also been approached.
  • Two separate American lobbies behind the rise of Donald Trump are clashing, over the nation’s biofuels program. In the fossil fuel corner, billionaire Carl Icahn wants to shift the responsibility of the ethanol blending mandate from oil refiners (where it currently lies) to fuel blenders, who oppose the regulation change that has the potential to effect the entire ethanol chain, including farmers that supported Trump.

Natural Gas and LNG

  • That Canada is an LNG powerhouse is not in doubt, but it has not actually exported a single parcel of LNG yet, waiting for its export facilities along the British Columbia to approach completion. In a roundabout way, however, the very first Canadian LNG parcel may be sold overseas this year…. from Louisiana. American LNG player Cheniere has been quietly building a portfolio of natural gas suppliers to support its Sabine Pass export terminal, and has now begun sourcing gas from as far as the Montney shale play, straddling Canada’s Alberta and BC provinces.

Corporate

  • Total and Brazilian state player Petrobras have sealed a ‘strategic alliance’ that will see both companies collaborate closely. Petrobras will be transferring rights to some of its domestic fields to Total, maintaining ownership of key assets while balancing its severe debt situation. Total is a strategic choice in this case with its open attitude to investment.


Last week in Asian oil:

Upstream & Midstream

  • Attempting to fulfil its ambitious forecast of tripling its crude production, Pertamina has been looking overseas for assets. Shut out of sites in Africa and Asia over competitive forces, Iran has been the main target on its radar. The state player has submitted official proposals to Iran’s NIOC to develop the Ab-Teymour and Mansouri fields, containing up to 1.5 billions of oil each, meeting the deadline set back in August 2016 when Pertamina and NIOC agreed to a MoU to evaluate the development of the fields.

Downstream & Shipping

  • China’s Sinopec has announced a US$29 billion plan to upgrade four refineries over the next four years, envisioning a literal brighter future by siphoning out the pollution responsible for the perpetual smog in China’s cities. The four sites – in Shanghai, Nanjing, Zhenhai and Zhanjiang – will have their collective capacity raised to 2.6 mmb/d (and ethylene capacity up to 9 million tons per year), representing 45% of Sinopec’s refining capacity. The fuel specifications will be based on the so-called National VI standard, up from the current Euro V, which is being implemented in Beijing this year and rolled out across China over the next four years.
  • China’s largest independent refiner is teaming up with CEFC China Energy and the Rizhao port authority to construct what is believed to be the first ‘teapot’-owned crude oil terminal in Shandong. Long restricted from importing crude until last year, China’s refined products output from independent refineries exploded last year, but also revealed a weakness – the complete lack of crude terminal facilities to serve the teapots. The logistical bottleneck has prevented the teapots from expanding further, so a move into storage and terminals is natural. Dongming Petrochemical, the largest such teapot, is planning to build a 300,000 deadweight tonnage (DWT) crude terminal, two 150,000 DWT crude berths and a 9.8 million barrel storage farm in Rizhao, south of Qingdao, China’s largest oil port by volume that is almost completely saturated.
  • Indonesia’s Pertamina expects to finalise its partner for the US$10 billion Bontang refinery by April. Unusually offering a majority stake in the 300 kb/d refinery – up to 95% – the move seems an admission that Pertamina simply does not have the capacity to develop its expansion plans alone. Rosneft and Saudi Aramco are names that have been linked as possible partners, but interest seems to have petered out, a chronic problem in Indonesia as ambition clashes with practical reality. This also casts doubt on Pertamina’s ability to develop the Balongan refinery expansion project on its own, after Saudi Aramco pulled out of the project last year.

Natural Gas & LNG

  • India’s state gas player GAIL has inked a deal with Swiss trader Gunvor for LNG cargo swaps. A glut in Asia has caused Asian spot LNG prices to fall sharply over the past six months, making it unfeasible economically to bring GAIL’s US LNG cargoes over. Gunvor will supply 800,000 tons of LNG to India’s west coast from its portfolio at more feasible prices, receiving 600,000 tons of Sabine Pass LNG in return.  GAIL went on a spending spree in the US, buying into natural gas assets during a period when prices kept rising, and now that the market has upended, is stuck with an overhang of expensive (and distant) gas.

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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