Last week in the world oil:
* With an extension of the OPEC supply cuts seemingly imminent, as Saudi Arabia and Russia agreed that the freeze must last until early 2018, crude oil prices have gained ground. Brent topped US$52/b for the first time in three weeks, while WTI is inching up towards US$50/b again.
Upstream & Midstream
* France’s Total has signed a deal with Mauritanian state oil firm SMHPM to explore for offshore oil and gas, as the action in West Africa swings north to the new deepwater basins off Mauritania and Senegal. Total will take a 90% operating stake in the 7,300 sq.km 7,300 Block C7, just a week after it bought a 90% stake in the Rufisque Offshore Profond Block in Senegal.
* First oil has begun to flow at the Repsol Sinopec Resources’ Shaw field, part of the major redevelopment of the Montrose Area in the Central North Sea. Aiming to integrate new and existing infrastructure in the UK’s North Sea, the Shaw, Godwin and Cayley fields will add some 100 million boe to the reserves in Montrose.
* The recent razor-thin victory of Canada’s Liberal Party in British Columbia puts the Kinder Morgan Trans Mountain oil pipeline expansion and the US$27 billion Petronas LNG export projects at risk. Reduced to a minority government, the Liberals will require support from the Green Party to govern, and the Greens are vehemently opposed to both projects, despite the BC and Federals governments already approving them.
* American oilrigs added another nine to their number, reaching 712. It has been 17 consecutive weeks of rises in the US overall rig count, marching towards 900 as raising doubts about the effectiveness of more OPEC cuts.
* Italy’s Eni will be building a new 150 kb/d refinery in Nigeria. Part of the country’s drive to boost downstream investment to reduce reliance on imported oil products – despite being a crude exporter – the refinery will be built by Eni’s downstream subsidiary Agip, replacing the chronic aging existing refineries of NNPC.
* Venezuela’s refining woes continue, as aging units and manpower shortages reduce utilisation at the Paraguna Refining Center to 43%, with multiple units at the Cardon and Amuay refineries out of service.
Natural Gas and LNG
* As East Europe looks to assert a measure of energy independence away from Russia, Romania’s state gas producer Romgaz announced that production at the domestic Caragele field will start in 2019. With an estimated 25-27 bcm of gas, the field in Buzau could supply the entire country for three years. Romgaz is hoping to up that figure, sanctioning more tests and drilling in the area, with an eye toward becoming a net gas exporter through the impending Bulgarian-Romanian gas pipeline.
* From being desperate for oil and gas, Egypt is now talking to its LNG suppliers to defer shipments as its domestic gas production surges. Long seen as a reliable sink for LNG shipments, Cairo reportedly aims to scale back LNG purchases in 2018 from 70 to 30 cargoes, as production surges from BP’s Tauros and Libra fields in West Nile Delta, as well as Eni’s Zohr and giant Nooros field, which has hit 900 million cubic feet/d of output.
Upstream & Midstream
* Saudi Aramco will ship some 7 million barrels of crude oil less to Asia in June. Part of its commitment to the OPEC pact, the reduction also comes as the country hoards crude for domestic power demand during the searing summer, especially with the festive Ramadhan period beginning in late May. The nomination plans for June indicate a million barrel cut to Southeast Asia, China and South Korea each, slightly less than a million barrels for Japan and a whopping 3 million barrels for India. Expect the countries to turn to America and Africa to make up the shortage.
* Total and Japan’s Inpex are proposing to the Indonesian government take a 39% stake in the new Production Sharing Contract (PSC) at the Mahakam block. Under the current contract that began in 2015, the two companies – which operate the oil and gas block – have a smaller stake of 30%, with Pertamina taking the rest. Pertamina will be the operator of Mahakam under the new PSC, with Total and Inpex asking for new clauses in compensation, including 17% investment credit for developing the block and selling gas to domestic buyers at market prices.
* IndianOil has opened up talks with Saudi Aramco to build a mega refinery on India’s west coast. The project would be one of mutual benefit. India is aspiring to be self-sufficient in oil product demand, which would require that it vastly expand refining capacity. The project, which has a mammoth planned capacity of 1.2 mmbpd will also have a petrochemicals portion, to feed the country’s growing manufacturing sector. For Saudi Arabia, it locks in India as a top customer amid a growing oil supply glut. It also represents a strategic downstream move, with Aramco also involved in the RAPID project in Malaysia and pushing ahead with its American Motiva subsidiary after a divorce from joint venture partner Shell.
* ExxonMobil has agreed to buy the Jurong Aromatics refinery and petrochemical plant, outbidding South Korea’s Lotte Chemical by offering a price of US$1.7 billion. The JAC plant will now be integrated with ExxonMobil’s existing complex on Jurong, expanding the firm’s largest refining complex even further.
Natural Gas & LNG
* Malaysia’s Petronas is looking to expand its status as the third-largest LNG exporter by tapping new market in South and Southeast Asia. India, Pakistan, Bangladesh and Myanmar have been identified as avenues of growth for the Malaysian state oil firm, while new sectors such as LNG fuel for commercial ships are also being tested.
* Without changing existing rules for American LNG exports, Donald Trump’s administration has clarified that current trade rules allow American shale gas producers to target China directly to sell LNG. Currently, American LNG heads to China under spot contracts, with Cheniere already shipping nine cargoes from its Sabine Pass facility. The clarification is expected to trigger a wave of long-term contracts with Chinese buyers, rather than prompt spot purchases.
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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.
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.
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