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Last Updated: May 25, 2017
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Last week in the world oil:

Prices

  • As confidence grows that the world’s top oil exporters will agree to extend the OPEC supply cuts, crude oil prices have hit their highest point in a month. Brent started the week at nearly US$54/b, while WTI managed to break past the US$50/b level to settled at almost US$51/b.

Upstream & Midstream

  • First oil has begun to flow at Quad 204’s, BP’s new upstream project in the west of Shetland region in the UK. The Schiehallion and Loyal fields in the area were originally developed in the mid-1990s and are now part of the Quad 204 redevelopment project led by BP with co-venturers Shell and Siccar Point Energy. Some additional 450 million barrels of resources are expected to be unlocked, with production lasting to 2035, and highlights the potential of the UK to develop its Atlantic energy resources.
  • Even as crude prices see-saw, US oil production as proxied by rig activity shows no sign of stopping. Sixteen new oil and gas rigs started up last week – 8 apiece – including 2 offshore rigs to bring the US active rig count above 900 for the first time in almost two years.

Downstream

  • In the footsteps of BP and Glencore, ExxonMobil is now the latest firm to target Mexico’s downstream market. The US supermajor announced that it would be investing US$300 million to established a network of Mobil fuel station in the recently opened Mexican sector. BP was the first to stake a claim in Mexico, and has reported that its plan to open some 1,500 service stations has been more promising than expected, leading to an increase in investment. Trader Glencore has established a deal with Mexico’s Corporacion G500 SAPI to establish some 1,400 G500 Network-branded sites, creating even more competition.

Natural Gas and LNG

  • As upstream action in the eastern Mediterranean heats up, Greece is making another attempt to strike gas. With Israel’s Leviathan and Egypt’s Zohar giant gas discoveries establishing the Levant Basin as a natural gas powerhouse, Greece has invited ExxonMobil and Total to test for natural gas in areas south of Crete island and western Greece. Previous attempts to elicit interest in the blocks failed, but the recent gas discoveries have changed the upstream outlook for the area.
  • South Africa will be looking to issue its first shale gas exploration licences this September, with Shell, Falcon Oil and Gas and Bundu Gas & Oil likely to receive permission to drill for shale in the onshore Karoo basin. South Africa has historically dependent on offshore production for its gas, but is now turning to onshore opportunities as production dwindles and the country attempts to wean itself off coal as a power plant fuel.

Corporate

  • Saudi Aramco will be setting up a petrochemicals subsidiary, putting it in direct competition with Saudi chemicals giant SABIC. The potential change comes as Saudi Aramco attempts to diversify and strengthen its downstream operations ahead of its planned IPO, to create more broad-based operations to be palatable to investors. Aramco has plans to triple its current chemicals production to 34 million tons by 2030.

Last week in Asian oil

Downstream

  • Fresh off its tie-ups in Malaysia and India, Saudi Aramco has announced another mega refining project, this time in China. The joint venture between Aramco and state-owned China North Industries Group (Norinco) will see the world’s largest crude seller and world’s largest crude importer build a 300 kb/d oil refinery with a 1 million ton/year ethylene cracker in Liaoning. The move will deepen the ties between the two nations, as Saudi Aramco looks to lock up long-term supply for its crude through strategic downstream investments. The project is unusual, as Norinco is primarily a defence manufacturer, and could be a signal that China is serious about opening up competition in its energy industry.
  • To the surprise of no one, Vietnam’s second refinery has been delayed. The US$7.5 billion Nghi Son site has been delayed to 2018 from 3Q17, as the refinery faced some mechanical troubles in test runs. The delay means that Vietnam will remain heavily dependent on oil product imports, which Nghi Son was expected to ease.
  • China’s section of the East Siberia Pacific Ocean (ESPO) pipeline will be completed by 2018. As China expands its crude import options, the pipeline connecting the city of Mohe at the Russian border to the city of Daqing will pump some 15 million tons/year of Russian crude to China.

Natural Gas & LNG

  • Italy’s Eni has started gas production at Indonesia’s Jangkrik ahead of schedule. Ten offshore deepwater subsea wells have been connected to the new Jangkrik Floating Production Unit (FPU), with production expected to scale up to 450 million cubic feet per day. Processed gas will be delivered onshore via a 79km pipeline, connecting to the Kalimantan Transportation System to the Bontang LNG plant.
  • Malaysia’s Petronas has signed a MoU with Gas4Sea to collaborate and promote LNG as a cleaner maritime fuel. The move is in line with Petronas’ aim of diversifying its LNG business, with the deal signed through its shipping affiliate MISC. Gas4Sea comprises French natural gas company Engie, and Japanese shippers Mitsubishi and Nippon Yusen Kabushiki Kaisha. Bunker fuels have traditionally been heavy fuel oil, but efforts to promote cleaner fuels have led the shipping industry to consider gasoil and LNG as alternate fuels.
  • Another month and another shutdown at Chevron’s Gorgon LNG plant. The eighth outage since the project began in early 2016, Train 1 has been shut down for at least a month to replace to a faulty flow-measurement device. Outages have plagued the project but Gorgon is slowly finding its footing, starting up Train 3 in March 2017. Chevron will also be boosting capacity on Train 2 of its other Australian project, Wheatstone, as partner Woodside targets production growth of 15% per year through 2020.
  • China has successfully extracted natural gas from methane hydrate deposits mined deepwater. Trapped in ice-like chunks, gas is extracted and processed in a floating platform unit platform in the Shenhu area of the South China Sea. The successful extraction paves the way for a new revolution in energy that would help boost Chinese domestic gas production over the long run. Commercial development of the resource is still far away, with 2030 named as a target date.

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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