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Last Updated: June 14, 2017
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Last week in the world oil:

Prices

  • Oil prices remain weak, but edged up at the start of the week on news that US inventories had declined and that Saudi Arabia would limit crude sales to Asia in July and slash shipments to the US. However, simmering geopolitical tensions in the Arabian Gulf and increased US drilling activity is likely to keep a lid on prices below US$50/b for a while.

Upstream & Midstream

  • Shell has lifted its declared force majeure on Forcados crude exports, bringing all of Nigeria’s oil export facilities online for the first time in 16 months, after local militants disrupted operations through a sustained series of sabotage. With Nigeria exempt from the OPEC supply cuts, it can now raise its production back to expected levels of 1.8 mmbpd.
  • After previous talks with the South Sudan government collapsed, France’s Total says that the country has reapproached the French major to resume talks on developing the B1 and B2 oil blocks. Tullow Oil is also involved in the negotiations as South Sudan seeks foreign investment to unlock its hydrocarbon potential. B1 and B2 are part of the three blocks that make up the former Block B, the largest untapped oil deposit in South Sudan and central to the government’s plans to raise production from 130 kb/d to 200 kb/d by end-2017 and 300 kb/d by end-2018.
  • Commercial production from Eni’s offshore Sankofa field in Ghana will start in July, three months ahead of schedule with production of 45 kb/d. This is Phase 1 of the US$7.9 billion Offshore Cape Three Points project, which includes expected 180 mcf/d output at the Gye Nyame gas reserve.
  • Libya’s major Sharara field has reopened and should resume normal production levels of 270 kb/d within the week after a short workers’ strike over medical treatment coverage for employees.
  • Total operational oil rigs in the USA reached 741 last week, adding 8 new units. Along with 3 new gas rigs, that brings the American total to 927.

Downstream

  • Utilisation rates at Venezuela’s 187 kb/d Puerto la Cruz refinery has dropped down to 16%, as the Mesa 30 crude it depends on is redirected to Cuba and Curacao. Mesa 30 is a superlight crude used to dilute heavy Orinoco oil, but also prized by PDVSA’s foreign clients. Cuba, in particular, has taken up to 1.4 mmbpd of Mesa 30 since March, providing valuable foreign currency but exacerbating Venezuela’s refining crisis.

Natural Gas and LNG

  • While the gas world focuses on selling LNG to Asia, France’s Total is also looking at alternatives to grow its gas business by investing directly in gas-consuming industries. It has identified Morocco and South Africa as key countries to invest in gas and power projects, which will support an LNG portfolio that is expected to double to 15 million tons by 2020. Total will be looking to get involved in a US$4.6 billion Moroccan LNG import project and a US$3.9 billion gas-to-power development in South Africa.
  • Greece will be launching a tender this month for the privatisation of the country’s natural gas grid operator DESFA, part of a condition of Greece’s bailout agreement with the EU and IMF. Azerbaijan’s SOCAR originally agreed to buy 66% of DESFAfor €400 million, but the deal later collapsed.

Last week in Asian oil

Upstream

  • Pakistan’s OGDC has struck oil in the Chabaro-1 well in Pakistan’s Khewari block. Test drilling has shown flows of 15 mcf/d and a tiny 20 bpd of condensate. This adds on to the Chhutto-1 well, also in the province of Sindh, with flows of 8.66 mcf/d of gas and 285 bpd of condensate. While small, the finds are also a signal that OGDC’s aggressive exploration is paying off, adding to its production level of 50 kb/d – representing half of Pakistan’s current oil output.

Downstream

  • In an unusual and coordinated move, an alliance of more than 20 of China’s largest independent oil refiners have urged the ‘teapots’ to work closely as a group to adhere to government rules on oil quotas and fuel taxes. Previously pursuing individual agendas, the importance of the teapots in domestic fuels and exports expanded in 2015 when they were first allowed to import crude directly. But with that came extra scrutiny. Accused by Sinopec and Petrochina of evading or under-paying taxes, the move is an attempt to band together and act as a single block to preserve and defend their interests as a whole, since the actions of a single errant member could cause negative consequences for all.
  • Iraq is planning to triple its refining capacity by 2021 to reduce its reliance on refined product imports. Capitalising on its vast crude reserves, Iraq is planning a second refinery in Basra (300kb/d), a 70 kb/d plant in Kirkuk, and a 150 kb/d facility with two Chinese companies, as well as upgrades to existing refineries in Basra and Daura. Assuming all projects are completed as scheduled by 2021, processing capacity in Iraq will rise from 500 kb/d to 1.5 mmb/d.
  • Financing issues have caused Indonesia’s Pertamina to rethink its schedule of upcoming refinery upgrades and its ventures with Rosneft and Saudi Aramco. Unable to juggle so many projects within a short period, the timeline will now be expanded to ensure that cost is not a burden concentrated within 1 or 2 years. The Balikpapan project, which would boost capacity to 360 kb/d from 260 kb/d has been pushed back to 2020 from 2019, with a second stage – aimed at improving fuel quality – delayed to 2021. The Cilacap upgrade project will be pushed to 2023 from 2021, pending Saudi Aramco sign-off, while the grassroots 300 kb/d Tuban refinery with Rosneft is likely to be moved to 2024 from 2021. All this will mean that Indonesia will remain highly dependent on fuel imports for the time being.

Natural Gas & LNG

  • As Australia aims to ease the gas shortage in its populous east coast, the Northern Territory has ok-ed the building of the Jemena A$800 million gas pipeline (owned by the State Grid Corp of China and Singapore Power), which will link the gasfields in northern Australia with consuming markets in Queensland. Meanwhile, further south, the state of Victoria is backing a floating LNG import project with AGL Energy to beef up its local gas supply. This is required since onshore gas drilling has been barred in Victoria, forcing the state to compete with LNG export projects pulling natural gas out of the country’s manufacturing hub.

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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