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Last Updated: March 29, 2017
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Last week in World Oil:

Prices

  • Crude oil seems stuck in its current range – US$48/b for WTI and US$51/b for Brent – as traders remain pessimistic of an extension to the OPEC supply freeze that, even if implemented, may not have much effect given the rise in American drilling that is sure to follow.

Upstream & Midstream

  • Permit for the Keystone XL oil pipeline has been issued by President Donald Trump. The battleground now shifts to courtroom, where activists and landowners are plotting regulatory and legal challenges to keep the TransCanada pipeline from moving ahead.
  • The 29th offshore licensing round in the UK North Sea has been completed, with 25 licences handed out to mostly majors, including Shell, BP, ExxonMobil and Statoil. Centred on frontier areas off the Hebrides and Shetlands, the success of the round indicates renewed vigour that has been gaining over the last year in what was once a declining area.
  • The US active rig count jumped by a massive 20 last week, led mainly by oil rig gains, as American drillers put faith in steady crude oil prices. The bulk of the gains were in the onshore Permian Basin, with gains in Eagle Ford and Marcellus shale plays as well.

Downstream

  • A shakeup is happening at PDVSA, where high-level managers across all refining and downstream divisions have been removed recently. Ostensibly to battle corruption, the changes while Venezuela is struggling to provide fuel for its citizens, with reports of long queues to buy gasoline as PDVSA struggles with debt, imports and distribution woes.
  • Shell has completed talks with Tesoro to lease its capacity at an oil terminal in Panama. The three-year agreement at Petroterminal de Panama, which has 14 million barrels of capacity, and a pipeline network connecting the Atlantic to the Pacific, bolsters Shell’s storage capacity in the Gulf and Caribbean, which anchors its crude trading operations.
  • The US government is considering retaliatory actions against Argentina and Indonesia over biodiesel dumping. Between 2014 and 2016, biodiesel imports from both countries have risen by 464%, prompting complaints by American biodiesel producers of underpricing. Indonesia, facing similar complaints from the EU, plans to protest together with Argentina.

Natural Gas and LNG

  • Unable to rely on Saudi Arabia to supply its energy needs, Egypt has been looking elsewhere, issuing a flurry of tenders late last year. The Egyptian Natural Gas Holding Company has signed an agreement with Russia’s Rosneft to buy 10 LNG cargoes this year, starting in May, up from three cargoes bought in 2016. Until Egypt’s natural gas discoveries, including Zohr, begin producing, tenders such as this will be more common. 

Corporate

  • Petrobras has raised its target for divestitures, aiming to raise US$21 billion over 2017 and 2018 in a bid to pare down debt. Despite legal challenges in Brazilian courts that have blocked several of attempted sales, Petrobras intends to accelerate its asset sales plan, while expanding joint ventures in key areas such as refining and E&P.

Last week in Asian oil:

Upstream & Midstream

  • A trend is emerging, as Japan’s Inpex has decided to exit the Natuna Sea in Indonesia. Selling its entire stake in subsidiary Inpex Natuna to Indonesia’s PT Medco Daya Sentosa (a subsidiary of PT Medco Energi Internasional), the sale will see Inpex leave the South Natuna Sea Block B. This follows ConocoPhillips’ decision to exit the Natuna Sea block last year, with PT Medco also gaining in that case. Inpex has been involved in the prodigious Natuna Sea since 1977, but returns have been dwindling recently with little replenishment, leading to declining interest.
  • Petronas is beefing up its presence in Myanmar, farming into two ultra-deep water exploration permits operated by Shell in the Rakhine basin of the Bay of Bengal. Petronas already operates the Yetagun field in Myanmar, and plans to boost involvement in Myanmar as it seeks to deepen its external asset base. With the upstream business in the country heating up, UK oilfield services firm James Fisher and Sons last week signed an MoU with Myanmar’s Royal Marine Technology to expand the country’s marine services industry.

Downstream & Shipping

  • China’s Sinopec has officially acquired its first major refining operation in Africa, following in the footsteps of its upstream division by paying almost US$1 billion for a 75% stake in Chevron’s South African downstream assets, which includes the 100 kb/d Cape Town refinery, the Durban lubricants plant and operations in Botswana. Sinopec will retain the Caltex brand for six years for all retail operations, before rebranding.
  • Indian Oil has inked an agreement with the government of Nepal to supply the landlocked Himalayan nation’s refined product demand for the next five years. This extends a supply agreement dating back to 1974, with the new contract involving 1.3 million tons of refined products, principally gasoline, diesel, jet fuel and LPG for cooking. A natural gas pipeline is also being considered, as well as a refined products pipeline linking Motihari in the Indian state of Bihar to Amlekhgunj in Nepal.

Natural Gas & LNG

  • As the gigantic Gorgon and Wheatstone LNG projects, collectively costing US$88 billion, approached completion, Chevron has signalled that it does not intend to sanction any further expansion. Instead, it will focus on boosting returns and perhaps smaller, linked developments, as the LNG industry adjusts to the slump in oil prices.
  • South Korea’s KOGAS has signed an agreement with Japan’s JERA and China’s CNOOC, as the world’s largest LNG buyers aim to boost cooperation as bargaining power in the LNG industry increasingly shifts from sellers to buyers. Jointly, the three companies buy a third of global LNG, and the agreement potentially creates an influential buyers’ club that could demand more favourable contracts and clauses.

Corporate

  • Indonesian President Joko Widodo has named Elia Massa Manik as the new CEO of Pertamina, tasked with turning around the beleaguered state giant. A relative outsider to the country’s vast oil and gas bureaucracy, Elia lands in the position with a solid reputation for restructuring state-owned firms, including turning around operations at his previous position as head of PTPN III, Indonesia’s state plantation company, and at PT Elnusa, Pertamina’s oil services subsidiary.
  • Malaysia’s oilfield services firm Sapura Kencana will now be known as Sapura Energy Berhad. Proposed in early February and adopted at the recent AGM, the name was chosen to reflect the firm’s ‘global corporate identity.’

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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