The Cowboy State is struggling. Low demand for oil, gas, and coal is crippling the local economy, and lawmakers are scrambling for solutions. Production has been limited and exploration for new wells has come to a grinding halt. But is there some relief on the horizon?

COVID-19 has taken a major toll on the oil and gas industry as a whole, but Wyoming, a state highly dependent on its abundance of natural resources, is really feeling the sting. And the dominoes are already starting to fall.

The rig count in Wyoming fell from 30 rigs in March to just two rigs in early June. Experts estimate that for every rig lost, around 100 oil and gas jobs cease to exist. And though oil prices have rebounded in recent weeks, a full recovery of Wyoming's oil and gas industry appears unlikely in the short or even medium term.

Even one of the Cowboy State's top producers is throwing in the towel. At least for now.

One of Wyoming's top oil producers, Ultra Petroleum Corp., filed for Chapter 11 bankruptcy Thursday evening. This is the result of months of financial problems sparked by the COVID-19 fueled downturn in energy markets.

Brad Johnson, Ultra Petroleum’s CEO explained, “After several months of liability management efforts and careful consideration of how best to navigate a challenging low commodity price environment and our debt levels, Ultra’s Board of Directors determined that a voluntarily filing for Chapter 11 reorganization provides the best outcome for the entity,” adding “This financial restructuring will result in an enterprise with very little debt, good liquidity and significant free cash flow that is underpinned by a large-scale, low-cost base of natural gas and condensate production.”

And that's bad news for Wyoming as a whole.

As one of the top producers - and taxpayers - in the state, Ultra's insolvency puts Wyoming's entire revenue in additional jeopardy.

Adding to the pain, Texas and New Mexico have had a significant advantage in this market. The nature of drilling in the south means that Permian producers are able to pull up natural gas as a free byproduct of oil production. This has made it difficult for producers in Wyoming who deal exclusively with gas.

While most of the natural gas in the U.S. comes from oil drilling operations, the collapse in energy demand worldwide makes it even more difficult for producers who only pump gas because they have nothing else to fall back on.

https://finance.yahoo.com/news/cowboy-state-hurting-low-oil-230000740.html

BASRA, Iraq (Reuters) - Iraq has agreed with major oil companies operating its giant southern oilfields to cut crude production further in June, Iraqi officials working at the fields told Reuters on Sunday.

Baghdad aims to improve its compliance with its output cut targets under a global deal with OPEC and its allies to reduce oil supply.

Iraq has agreed with Russia’s Lukoil to start an additional cut of 50,000 barrels per day (bpd) as of June 13 to lower production from the West Qurna 2 field to around 275,000 bpd.

Lukoil cut output by 70,000 bpd in May in response to a request by Iraq’s oil ministry, two Iraqi oilfield managers told Reuters on Sunday.

Production from West Qurna 2 was around 395,000 bpd in April, the managers said.

The Iraqi oil managers, who oversee production operations, said state-run Basra Oil Company had asked BP to cut production from the Rumaila oilfield by around 140,000 bpd of its total production, which stands at between 1.4 million bpd to 1.45 million bpd.

Exxon Mobile Corp has agreed also to cut an additional 70,000 bpd from the West Qurna 1 field to reduce production to around 350,000 bpd in June, the two Iraqi managers said.

Production was cut by around 50,000 bpd in May and stood at around 420,000 bpd.

Lukoil, BP and Exxon were not immediately available for comment.

Iraq has told OPEC it would start an urgent plan to cut its oil production gradually to fully comply with its quota, after the group demanded that Baghdad and other laggards adhere to a pact on output curbs.

"We will keep lowering production gradually to comply with OPEC quota," said one Iraqi oil official.

OPEC, Russia and allies agreed on June 6 to extend record oil production cuts until the end of July, prolonging a deal that has helped crude prices to double in the past two months by withdrawing almost 10% of global supplies from the market.

The group, known as OPEC+, also asked countries such as Nigeria and Iraq, which exceeded production quotas in May and June, to compensate with extra cuts in July to September.

https://finance.yahoo.com/news/iraq-agrees-oil-companies-deeper-164029611.html

The US oil and gas labor market is amongst the world’s most severely hit by the downturn that the Covid-19 pandemic has brought, a Rystad Energy analysis of the latest data from the US Bureau of Labor Statistics (US BLS) reveals. More than 100,000 oil and gas jobs have already been lost in total, with most of them coming from the support activities market.

The data shows that the four oil and gas segments most affected are support activities for oil and gas operations (44,550 jobs cut from a pre-Covid-19 level of 233,550), pipeline and gas and related construction (16,000 jobs cut from 227,000), drilling of oil and gas wells (13,450 jobs cut from 79,450) and oil and gas extraction (9,600 jobs cut from 156,600).

In addition to the above four segments from the US BLS, Rystad Energy has included more components of the oil and gas industry chain, thus independently estimating the total job cuts to exceed 100,000 to date. The support activities segment in particular reveals a staggering employment slump of 20% compared to February’s pre-Covid-19 levels.

“The job cuts can be attributed mainly to the nosediving oil prices driven by a sharp contraction in domestic oil demand, which has resulted in an unprecedented demand-supply imbalance. In response to the weakened demand, operators and service providers alike have been frantically cutting jobs,“ says Rystad Energy’s Vice President Energy Service Research Matthew Fitzsimmons.

Heavy construction labor demand in the US increased by 3.4% in May, but the oil and gas industry did not contribute to this increase. Since the outbreak of the pandemic in the US in early February, oil and gas construction jobs have decreased by more than 10%. We believe this sector within the oil and gas industry will take a more cautious approach to new construction activity, waiting for the safety risks associated with Covid-19 to recede.

While onshore construction workers can social distance and execute their tasks on duty, issues arise during tool-box talks, mid-morning, lunch, and mid-afternoon breaks. Spreading out the times for breaks and installing additional breakout trailers to minimize the risk from these situations can result in increased indirect costs.

In addition to battling the safety risks with ongoing work, various large operators are now delaying or pulling out of new facility construction. In Louisiana alone, more than 40% of liquefied natural gas (LNG) investments scheduled for this year have been postponed or canceled.

A revival in construction labor demand may take some time as delays mean weather windows for construction will be missed. In addition, the weak financial stability of service companies may leave them unable to ramp up hiring fast when conditions improve.

Job cuts aside, the ongoing downturn will also manifest itself in the form of deep pay cuts. According to our estimates, the wages for various trades in the oil and gas industry are likely to witness a decline of at least 8% to 10% heading into 2021.

The decline in wages and steep job cuts may see workers migrate to other industries with overlapping skill requirements, while some senior workers may retire altogether, as we saw in the previous downturn. Combined with social distancing measures, severe restrictions on international travel and stringent immigration audits, this will adversely impact the hiring of labor once prices and demand stabilize.

Some parts of the US have been affected more than others. Texas has lost more than 45,000 jobs in its upstream sector since February 2020. Similarly, Louisiana will likely see a decline of nearly 25% in its total oil and gas workforce, according to the Louisiana Oil and Gas Association.

“Overall, the impact of the job cuts would be greater for the oilfield services (OFS) sector than for exploration and production companies. OFS companies are likely to see more than 20% of its shale, onshore and offshore workforce combined cut by the downturn. While other industries have started to see labor demand embark on a road to recovery, oil and gas workers will have to wait longer for demand to increase,“ Fitzsimmons concludes.

https://finance.yahoo.com/news/u-already-lost-more-100-170000098.html

ADEN, Yemen (Reuters) - Yemen aims to raise its crude oil production by 25% to 75,000 barrels per day in the coming months, the energy minister of the country's internationally-recognised government said.

Saudi-backed Abd-Rabbu Mansour Hadi's government controls the eastern and southern areas where Yemen's oil-and-gas fields are located, while the Iranian-aligned Houthi group controls the capital Sanaa and the oil terminal of Ras Issa on the Red Sea.

"The oil ministry has put forward a plan to re-export crude oil from all oil fields in Marib and Shabwa ... and we have succeeded in rehabilitating al-Nashama oil port on the Arabian Sea," Hadi's government energy minister Aws Abdullah al-Awd told Reuters in an interview.

The civil war has choked its energy output, shuttered its Aden refinery and damaged its infrastructure, Awd said, raising questions about Yemen's ability to increase its crude production and rehabilitate the sector anytime soon.

Yemen's oil output has collapsed since 2015 when the Saudi-led military coalition intervened in a war to try to restore Hadi's government to power after it was ousted by the Houthis.

Yemen produced around 127,000 bpd before the conflict and the U.S. Energy Information Administration (EIA) estimates it has proven oil reserves of around 3 billion barrels. It has two primary crude oil streams, with light and sweet Marib and medium-gravity and more sulphur-rich Masila.

It is also working to build more pipelines and raise the limited storage capacity at Nashima port, which stands at 600,000 barrels compared to 3 million barrels in Houthi- controlled Ras Issa port, Awd said.

The minister also said he hoped that Yemen would resume production and exports of liquefied natural gas (LNG) from the Balhaf facility by next year, assuming improved security and a speedy recovery of global energy markets.

The plant, which was operated by France's Total, declared force majeure in 2015 due to worsening security.

https://finance.yahoo.com/news/yemen-aims-raise-oil-output-121453081.html

The U.S. Energy Information Administration (EIA) expects U.S. electricity demand to total 998 billion kilowatthours this summer (June through August), the lowest level of summer electricity consumption in the United States since 2009 and 5% less than last summer.

EIA expects electricity consumption to be lower this year largely as a result of efforts to reduce the spread of COVID-19. Most of the expected decline in retail electricity sales occurs in the commercial and industrial sectors, which EIA forecasts to be 12% and 9% less, respectively, than during summer 2019. EIA expects residential electricity sales to grow by 3% this summer because more people are working from home and following social distancing practices.

Normally, weather is one of the primary factors in determining electricity demand in the residential and commercial sectors. The National Oceanic and Atmospheric Administration (NOAA) forecasts that U.S. cooling degree days—an indicator of demand for air conditioning—for June, July, and August 2020 will be 1% lower than last summer.

This summer, however, other factors are affecting electricity demand more than temperature. Although state and local governments are relaxing stay-at-home orders, social distancing guidelines will likely result in Americans spending more time at home than usual this summer. In addition, many people that had worked in offices are now working from home, shifting electricity demand from the commercial sector to the residential sector.

Macroeconomic indicators are primary drivers in EIA forecasts for electricity consumption in the commercial and industrial sectors. EIA’s short-term economic assumptions are based on the macroeconomic model from IHS Markit. This model projects non-farm employment will fall by 13% in 2020 and that the electricity-weighted industrial production index will contract by 12% in 2020.

The amount of electricity generation from coal will likely be lower than last summer as a result of less electricity demand. EIA forecasts coal-fired power plants will generate 178 billion kilowatthours (kWh) between June and August 2020, down from 272 billion kWh last summer. Coal continues its downward trend in its contribution to U.S. power generation, and EIA expects its generation share will fall from 24% of the electricity generated during summer 2019 to 17% this summer. EIA forecasts the amount of coal generation to be lower than nuclear generation this summer (207 billion kWh).

EIA expects that natural gas-fired power plants will generate 467 billion kWh this summer, slightly higher than natural gas generation last summer (460 billion kWh). Forecast natural gas prices remain low this summer, making it relatively more economical than coal for power generation. EIA forecasts natural gas’s share of electricity generation to increase from 41% last summer to 44% this summer.

EIA also expects the renewable energy share of electricity generation this summer will increase compared with last summer. Significant additions of new wind and solar generating capacity, especially in the Midwest region and Texas, drive EIA’s forecast that U.S. wind’s share of electricity generation will grow to 7% this summer and utility-scale solar will grow to 3%.

EIA has published a supplement to the Short-Term Energy Outlook that provides more details about the summer 2020 electricity industry outlook.

https://go.usa.gov/xw5F3

Petrol and diesel prices were raised in metros on Sunday for the eighth straight day as state-run oil companies returned to the normal practice of daily reviews after a 12-week halt.

Petrol will now cost Rs 75.78 per litre after an increase by 62 paise and diesel Rs 74.03 per litre after its price was raised by 64 paise in Delhi.

In Mumbai, petrol is being sold at Rs 82.70 per litre and diesel at Rs 72.64 per litre. Customers in Chennai will have to pay Rs 79.53 for a litre of petrol and Rs 72.10 per litre for diesel.

Kolkata residents will have to pay Rs 77.64 for petrol and Rs 69.80 for diesel for every litre.

On Saturday, the prices of petrol were increased by 59 paise per litre and diesel by 58 paise per litre in Delhi as oil companies for the seventh day in a row adjusted retail rates in line with costs since ending an 82-day hiatus in rate revision.

Rates have been increased across the country and vary from state to state depending on the incidence of local sales tax or VAT.

The freeze in rates was imposed in mid-March soon after the government hiked excise duty on petrol and diesel to shore up additional finances.

Indian Oil Corp (IOC), Bharat Petroleum Corp Ltd (BPCL) and Hindustan Petroleum Corp Ltd (HPCL), instead of passing on the excise duty hikes to customers, adjusted them against the fall in the retail rates that was warranted because of a decline in international oil prices.

https://www.hindustantimes.com/india-news/petrol-diesel-prices-raised-in-delhi-to-cost-rs-75-78-per-litre-and-rs-74-03-per-litre-respectively/story-jpHTHHkis4mMg6nq7X5GFI.html&ct=ga&cd=CAIyGjFhODM5OTgwNmE5N2Q2NjA6Y29tOmVuOkdC&usg=AFQjCNGge5BOjNfBvKInM5K_ajJMv3BZd

As the Chinese economy starts to emerge from the depths of the coronavirus lockdown, oil producers are experiencing a spike in demand. The pandemic temporarily crippled the Chinese economy though over the past month the People’s Republic has started to ramp up activity, with oil demand now recovered to over 90% of its pre-coronavirus levels.

Industry analysts are hopeful the trend could be mirrored in other countries slowly relaxing lockdown measures. As well as lifted travel restrictions, government stimulus packages designed to bolster economies could help push up worldwide oil demand in the last six months of 2020.

Analysts hope for upward trend

Jim Burkhard, vice president and head of oil markets at IHS Markit says the Chinese recovery implies a positive outlook for the oil and gas industry as a whole. “The brisk resumption of Chinese oil demand, 90% of pre-COVID levels by the end of April and moving higher, is a welcome signpost for the global economy,” he says. “When you consider that oil demand in China - the first country impacted by the virus - had fallen by more than 40% in February - the degree to which it is snapping back offers reason for some optimism about economic and demand recovery trends in other markets such as Europe and North America,” he adds.

Sri Paravaikkarasu, an analyst at preeminent energy consultancy group FGE agrees, saying “China has led the demand recovery path so far.” She adds that in countries such as Australia, Vietnam and South Korea where COVID-19 cases are largely under control, a quick recovery in petroleum demand is also likely.

Hopes for swift price recovery

As well as demand, a price recovery is also on the radar of oil executives. By mid-April, the global coronavirus pandemic had slashed oil prices by around 70% and even forced WTI into negative territory for the first time in history. Now, benchmark oil prices are starting to bounce back, and China is at the forefront of the recovery. In the second half of 2020, Wood Mackenzie predicts Chinese oil consumption will grow to 13.6 million barrels per day (bpd), marking a 2.3% on last year’s figures.

“By the third quarter, China’s gasoline demand would have surpassed the same period last year by 3% to 3.5 million bpd,” reads a statement issued by the global consultancy group. Over the same period, Wood Mackenzie analysts expect to see a 1.2% increase in diesel demand.

While some outlooks are positive, others warn there could be turbulence ahead. In its May report, the International Energy Agency (IEA) predicted a 5% drop in Chinese oil demand in the second half of 2020, which could severely damage hopes of a swift recovery.

While the market is volatile, the energy industry is still powering ahead with new innovations. For a closer look at the latest breakthroughs don’t miss ‘VICI International AG - News and New Products for 2020.’

https://www.petro-online.com/news/analytical-instrumentation/11/breaking-news/how-is-china39s-recovery-driving-oil-demand/52458&ct=ga&cd=CAIyHGUzNTNmYzI0N2YyZGM3ODQ6Y28udWs6ZW46R0I&usg=AFQjCNHrf5ze2l44cv2_ph8MLp0JoJWdz

Canadian oil sands companies have shelved nearly C$2 billion in green initiatives in a cost-cutting drive to weather the coronavirus pandemic, a reversal in some of their commitments to reduce emissions and clean up their dirty-oil image.

International oil firms left Canada in droves in recent years due to the high costs to turn a profit in the sector. Some investors and banks, meanwhile, halted financing in part to pressure the world's fourth-largest crude producer to reduce the environmental impact of oil-sands production.

This year, top producers Suncor Energy, Canadian Natural Resources and Cenovus Energy have cut a combined C$1.8 billion ($1.32 billion) in planned spending on green initiatives as losses mount due to economic lockdowns that have hammered oil demand.

"This has strengthened our view on the matter, that our decision that we took (to block oil sands) was correct," said Jeanett Bergan, KLP's head of responsible investments.

KLP, Norway's largest pension fund, exited oil sands investments last year, while the country's $1 trillion wealth fund in May blacklisted Suncor and other large producers for producing excessive greenhouse gas emissions.

The Canadian industry has the highest upstream emissions intensity among major world oil and gas producers, at 39 kilograms per barrel of oil equivalent, more than triple that of the United States, consultancy Rystad Energy said in May.

The picture in Canada contrasts with Europe, where the biggest oil and gas companies have diverted a larger share of their cash to green energy, even through the outbreak.

The oil sands industry is more carbon-intensive than other forms of crude production, and faces more intense pressure from investors to limit emissions. Canadian oil producers will have a harder time convincing investors and environmentalists of their role in a future lower carbon economy if their commitment to green initiatives is wavering.

Canada's oil firms have invested in recent years to reduce their emissions intensity. But Western Canada's overall emissions increased 14% from 2005 to 2018, as oil output doubled.

INVESTMENT CUTS

Suncor, which made most of the cuts, shelved a C$300 million wind power project and a C$1.4-billion cogeneration plan, which would replace coke-fired boilers with natural gas units at its base operations, reducing carbon emissions and other pollutants.

Suncor vice president of sustainability Jon Mitchell said it and other green investments hinge on the financial health of the company's core business extracting crude.

"The deferral and delay in some of those projects does not diminish their importance," he said.

Cenovus, which is targeting net zero emissions by 2050, cut its technology budget by 78%, or C$137.5 million, saying in a filing it was only advancing select initiatives that had both cost and environmental benefits. The budget included work on green initiatives such as solvent-aided extraction and a new design for oil sands facilities.

A spokeswoman said Cenovus's commitment to green targets had not changed.

Canadian Natural put off a C$46 million pilot project that would reduce emissions by extracting bitumen at the mine face, limiting the need for trucks and equipment, the company said. A spokeswoman said that while the company has deferred some projects, its commitment to environmental targets remains.

Filings show that Suncor, Cenovus and Imperial Oil most recently budgeted roughly C$1.2 billion combined on research and development annually, which includes green initiatives, aside from capital projects.

Suncor, Canadian Natural and Imperial declined to say how much of those budgets have been cut this year. MEG Energy did not respond.

Alberta, heart of most of Canada's production, reduced environmental monitoring requirements temporarily, saying it was necessary to comply with health orders regarding the pandemic. The suspended types of monitoring included certain water quality tests and some monitoring of soil and wildlife.

Alberta's move is worrisome, said Jamie Bonham, director of corporate engagement at NEI Investments, a firm focused on responsible investing, which holds stakes in the sector to advocate for green improvements.

"The province is simultaneously opening up the economy - you can go to a barber, get a massage or sit in a restaurant - but you can't take an environmental reading at a wellsite?" Bonham said.

The pause is only for "short-term relief," said Kavi Bal, spokesman for the province's energy minister. He noted that a major commercial carbon capture project began operations this month.

The federal government has used pandemic aid to launch two new green initiatives - cleaning up abandoned wells and loans to help companies reduce methane emissions.

Such steps, however, are too little and too late to draw back many investors, banks and insurers that shunned the industry in recent years, according to a Reuters survey.

Eight investors, banks and insurance companies reached by Reuters, including Royal Bank of Scotland and France's AXA, that publicly reduced their oil sands involvement in recent years over climate change said industry efforts to reduce environmental impacts did not change their opposition to the sector.

While Canada has set a target of net-zero emissions by 2050, it has not outlined a plan. "Right now we do not have one," Natural Resources Minister Seamus O'Regan said in May on a panel.

https://www.marketscreener.com/news/Canada-s-oil-patch-cuts-back-climate-efforts-under-pandemic--30769112/&ct=ga&cd=CAIyGjQ4NjQyYzljOTM0YjI2YmU6Y29tOmVuOkdC&usg=AFQjCNG-WVAfu5OyOg9f1vip3ZHFL_cSz

TEHRAN — The parliament speaker’s special aide for international affairs rejects as “baseless” the UN secretary general’s report claiming that the missiles that hit the Saudi Aramco where of Iranian origin.

“The UN Sec report claiming missiles hit Saudi Aramco w/Iranian origin is a politicized move & baseless allegation,” Hossein Amir-Abdollahian tweeted on Sunday.

“Roots of regional insecurity must be sought in Tel Aviv, Riyadh bahavior,” he wrote. “#Iran has the most constructive role in establishing regional & global sustainable security.”

UN Secretary-General Antonio Guterres told the Security Council in a report seen by Reuters on Thursday that cruise missiles used in several attacks on oil facilities and an international airport in Saudi Arabia in November 2019 and February 2020 had been of “Iranian origin”.

He also said the “items may have been transferred in a manner inconsistent” with Security Council Resolution 2231, which enshrines the international nuclear deal – officially known as the Joint Comprehensive Plan of Action (JCPOA) – signed between Iran and world powers in 2015.

Guterres said in his report that the United Nations had examined the debris of weapons used in the attacks on an oil facility in Afif in May, the Abha international airport in June and August, and the Aramco oil facilities in Khurais and Abqaiq in September.

Tehran says the allegations were leveled under political pressure from the U.S. and Saudi regimes.

In a statement on Friday, Iran’s Foreign Ministry expressed deep concern over the abuse of the UN Secretariat for political purposes.

“While the Secretariat has treated with utmost tolerance and leniency towards these violations so far, it is now surprisingly engaged with an issue in which it has no authority to point out highly technical and legal findings, and its so-called technical report is in no way in line with the practical arrangements of the United Nations Security Council Resolution 2231 to perform its functions,” the statement read.

“Levelling accusations against other states using self-created processes and arbitrary procedures is a dangerous heresy, which is not accepted by the international community,” the Foreign Ministry warned.

Iran’s ambassador to the United Nations Majid Takht-Ravanchi also condemned the report, saying it has been made under political pressure from the U.S.

Iran rejects allegations in the UN Secretariat report, including the “Iranian origin” of the arms, Takht-Ravanchi said via Twitter on Friday.

“UN Secretariat lacks capacity, expertise & knowledge to conduct investigations,” Takht-Ravanchi wrote.

“Seems the US—with its history of Iran-bashing—sits in the driver’s seat to shape UN ‘assessments’,” he added.

https://www.tehrantimes.com/news/448880/Advisor-rejects-Guterres-report-on-Aramco-incident&ct=ga&cd=CAIyHGMzMDI4NGM4N2E3MjhhZTM6Y28udWs6ZW46R0I&usg=AFQjCNGYG72np6sEvgY1vyF0_OY_UbM4b

Muscat, Jun 14 (ONA) --- The Sultanate’s oil production, including condensates, stood at 124,100,900 barrels until the end of April 2020, according to the latest data released by the National Centre for Statistics and Information (NCSI).

Of the total production, crude oil production was up by 3.4% at 106,196,900 barrels while condensates production rose by 30.3% to touch 17,904,000 barrels.

The Sultanate recorded a daily average crude oil production of 1,025,000 barrels at the end of April 2020, against 970,500 barrels over the same period of 2019, the NCSI report added.

However, the average price of Oman Crude rose by 0.1% to reach USD62 per barrel till the end of April 2020, from USD61.9 per barrel in the same period of 2019.

The Sultanate exported 96,596,800 barrels of crude oil until the end of April 2020, against 96,518,600 barrels for the same period of 2019, falling by 0.1%.

In terms of exports, China retained its position as the leading destination for the Sultanate’s crude oil exports till April 2020, with the country importing 85,369,900 barrels of crude. This was followed by India (2,948,400 barrels), South Korea (1,830,00 barrels and Japan (608,200 barrels).

Oman’s natural gas production and imports rose 1.3% to 14.756 billion cubic meters at the end of April 2020, from 14.564 billion cubic meters for the same period of 2019.

Of this, non-associated gas and imports rose by 2% to 12.132 billion cubic meters and associated gas production fell 1.6% to 2.624 billion cubic meters, added the NCSI report.

The use of natural gas in industrial projects fell by 16.4% to reach 47 million cubic meters at the end of April 2020, against 57 million cubic meters for the same period of 2019. As much as 3.545 billion cubic meters of natural gas was used in oil fields, against 2.971 billion cubic meters consumed during the same period of 2019.

http://omannews.gov.om/en-us/NewsDescription/ArtMID/392/ArticleID/14524/Crude-Oil-Production-Rises-34pc-until-April-2020-in-the-Sultanate&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNEXoXcgwj-Y6usx09i0n9Fl5Hefr

OPEC+ Extends Cuts and Eyes a Demand Recovery

At a drama-free virtual gathering last weekend, the Organization of the Petroleum Exporting Countries (OPEC) and the broader OPEC+ group agreed to extend current production cuts by another month, through July. With Mexico now excluded, the targeted production cut for June and July is 9.6 million barrels per day (b/d) below October 2018 levels, falling to 7.7 million b/d for the rest of 2020 and to 5.8 million b/d from January 2021 to April 2022. The duration of this deal is unusual for OPEC. But it will be revisited throughout this period, and future adjustments are very likely.

The current OPEC cut is the largest in history, and so far, production restraint appears to be working. U.S. inventory builds have slowed since the rapid stockpiling earlier this spring, and West Texas Intermediate (WTI) crude prices have nearly doubled since late April, nearing $40 per barrel as of June 9. Both ICE Brent and Nymex (WTI) crude prices are still in contango-with future prices exceeding current prices, signaling weak demand from refiners, and providing strong incentives to store oil-but the contango has narrowed significantly. OPEC hopes the market will soon flip to backwardation, with stronger front-month prices helping to drain enormous inventories (although inventory draws will reduce demand for new supplies).

On June 8, Saudi energy minister Abdulaziz bin Salman cited 'good indicators that demand is coming back and thriving'-and much of this optimism stems from China's recovery. According to official customs data, China's oil imports surged to an all-time high of 47.97 million tons (11.3 million b/d) in May, and independent refiners increased their run rates to 78 percent last month (Oilgram News, S&P Global Platts, June 10). The strong recovery in China-where oil demand dropped by as much as 40 percent in February-has optimists convinced that global oil demand will rebound later this year as more economies reopen.

OPEC has hardly declared victory but seems more comfortable with the outlook for the second half of 2020. Saudi Arabia has increased its official selling prices for July exports for all regions, and Abu Dhabi followed suit. Riyadh and several other Gulf states also plan to end their additional cuts of 1.2 million b/d in July. Hopes for a strong second half are reflected in the International Energy Agency's outlook, which envisions a nearly V-shaped recovery that would create global stock draws as soon as the third quarter (see chart below).

Uncertainties Abound

While the worst of the demand shock appears to be over, a smooth recovery is unlikely. First, there is a risk of extrapolating too much from China. Much of the increase in crude imports over the last two months is due to opportunistic buying for both refinery and strategic stocks. China's independent refineries, which have benefited from easier access to import licenses this year, had strong incentives to ramp up crude buying when prices were low. Refiners in China also benefit from rules that place a floor on product prices when crude prices hit $40 per barrel, boosting refining margins as the oil price drops. In short, even with a strong recovery in Chinese industrial and transportation demand, crude imports and refinery runs should taper in the coming months.

Across most of the world, refining margins remain very weak and will shrink if OPEC and non-OPEC supplies ramp up in the coming months without a corresponding increase in product demand. Higher sales prices from Middle East producers to the all-important Asia market could harm demand. Another obstacle is the glut of product inventories in many markets, especially for diesel and jet fuel due to depressed economic activity and lack of air travel. Efforts to cut jet fuel production have forced refiners to produce more diesel, adding to inventories. The outlook for gasoline is brighter, but in the United States, gasoline inventories in the past month have remained well above the five-year average.

More broadly, it is impossible to predict how Covid-19 will affect oil demand in the second half of 2020 and beyond. Lockdowns, restrictions on travel, and preferences for telecommuting seem likely to continue for months in much of the world, perhaps until a vaccine for the novel coronavirus is developed. A spike in infections in any number of countries could have severe effects on demand. Without sustained increases in oil demand, the risk is that even modest increases in production will inevitably lead to bloated inventories, which will need to be worked off to sustain higher prices. The inventory overhang partly explains why Brent crude prices have not risen far beyond $40 per barrel in recent weeks.

Internal and External Challenges for OPEC+

Facing an unprecedented demand shock, OPEC+ has pulled together to reduce the supply surplus, and compliance last month was strong. The 10 core OPEC states met about 85 percent of the targeted cuts. (Iran, Venezuela, and Libya are exempted.) Russia, surprisingly, has nearly met its target of around 8.5 million b/d, perhaps because its key export markets have taken such a hit. The Joint Ministerial Monitoring Committee (JMMC) of OPEC+ will now meet monthly to gauge market conditions and enforce the party line on compliance.

But as ever, OPEC countries will be tempted to cheat, especially as oil prices rise. Laggards in the OPEC+ group include Angola, Nigeria, Kazakhstan, and especially Iraq, which reported production volumes of 4.21 million b/d in May-well above its agreed target of 3.59 million b/d. Last weekend's OPEC statement stressed that countries that fail to meet targets in May and June will have to make even deeper cuts from July to September to make up the difference. Longtime OPEC observers realize this amounts to magical thinking. Iraq, in particular, has routinely failed to meet its targets, and a new government facing financial strains and political pressures will have incentives to generate as much revenue as possible. Outside the bounds of the agreement, Libya's evolving security situation could also allow a gradual increase in output, although any gains could be subject to sudden reversals, depending on control of fields and export terminals.

Finally, OPEC will continue to grapple with the uncertainties of U.S. shale. The rig count across all basins continues to show steep declines, with 141 active rigs in the Permian Basin as of June 5, down from 403 at the start of the year. From a peak of around 13 million b/d in February, the Energy Information Administration estimates that U.S. output fell to 11.4 million b/d last month, although production could actually be far lower. Already, however, there are signs that stronger prices will lead to marginal production increases,as struggling companies seek to boost cash flows. This is perhaps to be expected, given the scale of retrenchment in the past few months. Without a durable increase in WTI prices to at least $45 to $50 per barrel, most companies fail to generate free cash flow, and investors are demanding capital restraint. But with regard to the United States, OPEC faces a familiar problem: the oil price most OPEC states need to manage their economies is high enough to incentivize more shale production.

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BP Plc will write down the value of its business by as much as $17.5 billion, as the British oil major predicts that the coronavirus pandemic will hurt long-term demand and accelerate the shift to cleaner energy. The company is also undertaking a review of its projects that could result in some oil discoveries being left in the ground.

It’s the latest in a series of big shifts from BP, which has pivoted sharply toward clean energy under its new Chief Executive Officer Bernard Looney. Shares fell 5% to 307 pence as of 8:15 a.m. in London.

“BP now sees the prospect of the pandemic having an enduring impact on the global economy, with the potential for weaker demand for energy for a sustained period,” the company said in a statement on Monday. “The aftermath of the pandemic will accelerate the pace of transition to a lower carbon economy.”

BP’s actions will lead to non-cash impairment charges and write-offs in the second quarter, estimated to be in a range of $13 billion to $17.5 billion post-tax, the company said. In February, BP outlined its ambitions to become a “net- zero” company by 2050. The company acknowledged that production will decline in the long term, and said whatever is pumped in 2050 “will have to be de-carbonized.” Peers including Royal Dutch Shell Plc, Total SA and Equinor ASA have also set out agendas for what’s becoming an existential challenge for the oil industry.

BP’s revised investment appraisal long-term price assumptions are now an average of around $55 a barrel for Brent crude and $2.90 per million British thermal units for Henry Hub gas, from 2021-2050, the statement shows. “These lower long-term price assumptions are considered by BP to be broadly in line with a range of transition paths consistent with the Paris climate goals,” it said. “However, they do not correspond to any specific Paris-consistent scenario.” BP is scheduled to publish its second-quarter results on Aug. 4.

Saudi Arabia’s oil giant Aramco has cut the crude oil shipments loading in July to at least five of its customers in Asia, Reuters reported on Monday, quoting sources familiar with the plans.

The move from OPEC’s top producer and the world’s largest oil exporter comes after Saudi Arabia hiked its official selling prices (OSPs) for July by the most in at least 20 years.

Last week, after the OPEC+ group had agreed to extend its record collective cut of 9.7 million bpd by one month to the end of July, Saudi Aramco sharply raised its prices for all grades to all regions.

The pricing of Saudi crude, typically released around the fifth of each month, generally sets the trend for the pricing for Asia of other Gulf oil producers such as Kuwait, Iraq, and Iran. The pricing of Saudi Aramco, the Kingdom’s oil giant, affects as much as 12 million barrels per day (bpd) of Middle Eastern crude grades going to Asia.

Although an increase in Saudi Arabia’s prices didn’t come as a surprise, the steep rise for July really surprised refiners, especially those in Asia, who had enjoyed three months of very cheap supply from Saudi Arabia, when the Kingdom was keeping its prices low to boost market share while demand was crashing in the pandemic.

“Increased OSPs have caught us by surprise and these are not attractive to refiners specially in a market where refining margins are weak,” R Ramachandran, head of refineries at India’s BPCL, told Reuters.

Due to the steep increase, at least one major Saudi crude oil buyer in Asia has nominated nearly one-third lower supplies from the Kingdom for July, a source with direct knowledge of the nominations request told Reuters.

Other refiners in Asia will likely look to buy more competitively priced arbitrage oil cargoes from the United States and West Africa and cut supply of what is now more expensive crude oil from Saudi Arabia and the Middle East as a whole, some of Reuters’ sources said.

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At 10:17 am Singapore time, ICE Brent August crude futures was 26 cents/b (0.65%) lower from June 15's settle at $39.46/b, while the NYMEX July light sweet crude contract was 25 cents/b (0.67%) lower at $36.87/b.

Sentiment took a risk-off tone in Asia trading, despite prices settling higher on June 15 during the US trading hours, amid news of additional economic support by the Federal Reserve.

"A full recovery to early March levels will need continued supply discipline, demand recovery, and time to work off US inventories and spare capacity," Axicorp chief global markets strategist Stephen Innes said in a June 16 note.

Concerns over a second wave of COVID-19 infections amid easing lockdowns continued to cloud the demand outlook.

The market is also looking towards fresh US inventory data to be released later in the week. The data last showed a substantial build, which dampened sentiment.

"A tall order indeed that could be prone to less satisfactory results over the short term, but a draw in this week's inventory data will go a long way to soothe supply concerns," Innes said.

On the OPEC+ front, some bullish sentiment emerged from reports that Iraq is adhering to the accord. Baghdad had signaled that it would sharply cut back on oil exports in June, Platts reported.

There were also concerns as to whether US shale production will increase as prices get supported by the OPEC+ cuts.

Meanwhile, the ICE Brent crude futures market structure had remained largely steady at the prompt, amid a lack of fresh drivers at the moment.

"Whether it [ICE Brent] can reverse last week's bearishness and embark on another bullish run remains to be seen, given that the contango spread is still relatively flat now compared to last month," OCBC analysts said in a June 16 note.

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Tokyo — At least two Japanese refiners have received confirmation from Saudi Aramco they will receive full volumes for July loading, company sources told S&P Global Platts June 15, a strong indication the country may not see the kind of cuts in crude volumes seen in June.

There had been market talk of allocation cuts to customers in Asia, according to Japanese and other regional market sources.

OPEC+ recently extended the coalition's 9.6 million b/d output cut agreement through July. Under the deal, Saudi Arabia will hold its crude production to 8.49 million b/d.

Some Japanese refiners were said by sources to be seeking full Saudi crude allocations for July in the wake of recent demand recovery from the coronavirus pandemic, according to company sources.

Japan's crude throughput rose for the first time in seven weeks at the start of June, with domestic gasoline demand recovering to pre-state of emergency levels. Crude throughput was expected to increase further in coming weeks as several refineries are slated to be restarted from scheduled and unscheduled shutdowns.

"We are grateful of the [supply volume]," one of the Japanese refiner sources said, noting the recovery in demand for oil products.

Domestic gasoline demand has been recovering in recent weeks during weekends, following the lifting of the state of emergency, which was declared April 7 to curb the spread of the coronavirus pandemic, on May 25 after bottoming out during the Golden Week national holidays over late April to early May, according to local market sources.

Japan's estimated gasoline shipments rose 7.5% to 5.04 million barrels in the latest week, above the pre-state of emergency level of 4.72 million barrels over April 5-11, according to calculations by Platts based on Petroleum Association of Japan data.

Strengthening spreads

Market participants were digesting June 15 Saudi Aramco's crude allocations for July, which has just been issued to term holders.

Traders have indicated that large cuts to allocation of Saudi barrels could provide further support to the Middle East crude market, which has already strengthened from the previous month.

Reflecting an uptick in sentiment on the Middle East crude market, the Dubai crude cash/futures (M1/M3) spread rose from a one-week low at the Asian close on June 15, Platts data showed.

The spread -- a key indicator of spot market sentiment for sour crude in Asia -- was assessed at 68 cents/b at the 4:30 pm (0830 GMT) Singapore close, up from 62 cents/b on June 12.

Last week, Saudi Aramco raised the official selling price differentials of its crude heading for Asia in July by $5.60/b-$7.30/b from the June OSP.

It sets the price differential of Asia-bound Arab Light crude at plus 20 cents/b against the average of the Dubai and Oman benchmarks over July, up by $6.10/b from the June price and higher than the $2-$5/b increase that traders had expected, according to a Platts survey.

June cuts

Previously, Japanese refiners have received larger-than-expected cuts to their June-loading term crude supply from OPEC producers, keeping them balanced against plummeting domestic demand due to the coronavirus pandemic, Tsutomu Sugimori, president of the Petroleum Association of Japan said May 22.

Saudi Aramco has told at least one Japanese refiner it will reduce its June-loading crude allocations by 20%-40%, with the cuts being made across all grades and with larger cuts to heavier grades.

"The June loading [volume] was shocking," a source with a Japanese refiner said.

Sugimori, speaking in his capacity as JXTG Holdings president, said May 20 the company had a good balance of product supply and demand due to refinery run cuts and maintenance, coupled with reduced crude supply from its major term suppliers, such as Saudi Arabia.

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New York — US crude inventories are expected to have fallen last week amid weather-related Gulf of Mexico production losses and a drop in imports, an S&P Global Platts analysis showed June 15.

Inventories likely fell by 3.5 million barrels to roughly 535 million barrels, based on the most recent US Energy Information Administration data. Still, that would leave stocks at around a 13.5% surplus to the five-year average.

Inventories have climbed this year because of low demand caused by the coronavirus pandemic. US Gulf Coast inventories at 303.7 million barrels the week ending June 5 were 27% above the five-year average, EIA data showed.

Offshore platforms were in the process of returning last week after shutting down ahead of Tropical Storm Cristobal, which made landfall on the Louisiana Gulf coast June 6. At its peak on June 7, Gulf of Mexico operators had reduced output by 636,000 b/d. By June 12, just 120,079 b/d of crude output remained down, according to the US Bureau of Safety and Environmental Enforcement.

Crude imports were also likely lower last week, which would help draw down crude stocks. Kpler vessel tracking software shows a total of 23.6 million barrels of waterborne crude imported into the US last week, down roughly 1 million barrels from the prior week.

Refinery runs strengthen

Also, refinery utilization is expected to have climbed last week, ticking up 1.3 percentage points to 74.4% of capacity, analysts said. Refiners began slashing runs in mid-February because of low demand, especially for gasoline, as the coronavirus pandemic closed businesses and kept drivers at home.

By the week ending May 8, refiners had reduced crude runs by 3.83 million b/d to 12.4 million b/d, EIA data shows. However, refiners have since lifted crude runs by 1.1 million b/d as states have started to lift business and travel restrictions.

Any boost in refinery runs would help to reduce crude inventories, however, US crude exports are expected to remain depressed. Buyers overseas are expected to turn to crude in floating storage before fixing fresh shipments from the US.

Roughly 175 million barrels of crude is currently sitting in floating storage, according to S&P Global Platts Analytics.

US waterborne exports averaged 2.35 million b/d last week, data from cFlow, Platts trade-flow software, showed, up from 2.23 million b/d the week ending June 5 but down from the 3.5 million b/d level seen in early May.

Diesel surplus grows

With some lockdown restrictions being lifted, inventories of gasoline are expected to have fallen last week by 2.2 million barrels, according to analysts. However, distillate stocks are expected to have risen by 3.1 million barrels, as the travel restrictions primarily impacted gasoline consumption, not industrial diesel demand.

US distillate stocks have risen 53.58 million barrels since the end of March to 175.83 million barrels, putting stocks at a nearly 30% surplus to the five-year average, EIA data shows.

USGC stocks have been driven higher by a drop in export demand to the Latin America and the Caribbean, where countries have also imposed restrictions due to the coronavirus.

However, exports have edged higher the past two weeks. Distillate exports nearly doubled to 1.4 million b/d the week ending June 5, EIA data showed. Kpler data shows refined products exports slipping for the week ending June 12 but remaining above the lows seen in mid-May.

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Washington — US shale oil production will slip to 7.632 million b/d in July, down 93,000 b/d from June and the lowest in two years, the US Energy Information Administration said June 15.

EIA trimmed its estimate for June production by 97,000 b/d from last month's outlook to 7.725 million b/d, according to its latest Drilling Productivity Report.

Permian Basin oil production is expected to fall to 4.27 million b/d in June, down 20,000 b/d from last month's outlook. EIA expects the West Texas/New Mexico basin to pump 4.263 million b/d in July, the lowest since May 2019.

US crude production from onshore shale basins peaked in March to just above 9 million b/d, before freefalling global oil demand from pandemic lockdowns and excess supply from Saudi Arabia and Russia tanked global oil prices.

Oil production is set to decline month on month in all seven major US shale basins in July, with Texas' Eagle Ford leading the declines on a volume basis. EIA expects Eagle Ford drillers to pump 1.173 million b/d in July, down 28,000 b/d from June and the lowest since August 2017.

Bakken production in North Dakota and Montana is expected to slip to 998,000 b/d in July, down 5,000 b/d from June and the first time below 1 million b/d since January 2017.

North Dakota regulators said June 12 oil production in the state may have bottomed out in mid-May with shut-ins topping 500,000 b/d. The state estimates current output at 925,000-970,000 b/d.

DUCs fall further

US drilled-but-uncompleted wells, or DUCs, fell to 7,591 in May, down 33 from April, EIA said in the same report.

The number of DUCs has fallen from a recent peak of 8,673 in May 2019, according to EIA data, as drilling and rig activity slowed in response to lower oil prices.

In contrast, S&P Global Platts Analytics estimates current DUCs at 5,065. The difference stems from the way DUCs are counted: Platts Analytics does not include so-called "retired" DUCs, which have waited on completion crews more than two years.

Platts includes only those that have just been drilled and are simply waiting for equipment to come onsite to complete the fracking, and DUCs that are deferred due to a poor price environment, pipeline constraints or operator strategy.

Once oil prices recovered from the downturn of 2015-2017, instead of drilling new wells, operators elected largely to first complete DUCs since they had already sunk 25%-35% of the total well cost in them. That is why some analysts believe DUCs may build during the current price downturn and operators may complete them toward year-end and build production momentum going into 2021.

But the US rig count, which dipped to a historic low of 299 last week, may not grow until next year, analysts say, adding increases may be slow to recover as operators more cheaply complete DUCs.

Andrew Cooper, an analyst for Platts Analytics, said rig counts should "return slowly" starting in early 2021 and return to pre-WTI crash levels in the low- to mid-800s by Q1 2023.

Rystad Energy said June 12 the slowdown in US fracking activity has added 750 DUCs in the past three months, the equivalent of a two-year backlog at the current pace.

"Usually there is a typical DUC buildup during winter months and a gradual drawdown during the spring and summer months," said Artem Abramov, Rystad's head of shale research. "Contrary to the norm, in the last three months this metric jumped to 15 to 25 months of frac activity. However, in the second half of 2020, we might see a modest rebound in fracking without extra drilling."

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UAE sees oil prices returning to ‘normal’ on OPEC+ deal

DUBAI (Bloomberg) - Oil-production limits adopted by a group of major crude suppliers will soon bring prices back to “normal,” according to the energy minister of the United Arab Emirates.

When markets were collapsing as the coronavirus pandemic crushed demand in March and early April, the idea that crude could rise again to $40 a barrel was “a dream,” the UAE’s Suhail Al Mazrouei said during a conference call on Monday. That was before the OPEC+ alliance agreed unprecedented cuts in output.

Prices could return to “normal” within a year or two as curbs approaching 10 million barrels a day drain excess barrels from the market, Mazrouei said during the call hosted by the Atlantic Council, a Washington-based research institute.

“We have seen very good signs of demand picking up,” Mazrouei said. “We have seen numbers of driving vehicles are picking up,” he said, citing demand growth in China, India and Europe.

Hinging on Lockdowns

Still, the direction of oil prices will hinge to a large extent on whether a second round of infections forces economies into lockdowns once again, he said.

“Are we going to have a second wave or not?” he said. “I hope not. I hope we’re not going to limit travel and we will go back to at least a consumption level that is reasonable. Now we are back to the consumption level of 2013, believe it or not.

Mazrouei didn’t specify what he meant by “normal” prices. However, benchmark Brent crude averaged about $64 a barrel last year. OPEC+ producers negotiated cuts in April to counter the pandemic’s impact and this month extended the reductions through July.

Led by Saudi Arabia and Russia, the group aims to support a rally that’s seen Brent more than double to around $40 a barrel since late April, paring its loss this year to 40%. For that success to continue, all OPEC+ members must adhere to their production quotas, while other suppliers must refrain from resuming output too quickly, Mazrouei said.

“In previous deals we had countries cheat because there was no rule. Now there is a rule, so countries are coming and stating their commitments,” Mazrouei said. The OPEC+ agreement has effectively created a “permanent” group of nations -- one bigger than the Organization of Petroleum Exporting Countries -- that will coordinate to manage crude markets, he said.

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SINGAPORE (Bloomberg) --Brent crude rose above $40 a barrel as broader markets rallied on stimulus from the Federal Reserve and physical supplies continued to look tight.

Futures in London rose for a second session. India’s oil minister said consumption in the first half of June had recovered to levels about 15% to 20% below a year ago, the latest sign of a recovery in global consumption. It came as the International Energy Agency warned in its monthly report that fuel use will remain 2.5% lower next year than in 2019, mostly because of a slow rebound in jet fuel consumption.

Those concerns are being partly assuaged as the U.S. Federal Reserve said it would start buying a broad portfolio of corporate bonds, aiding sentiment across financial markets. At the same time, there’s evidence OPEC+ members are complying with extended production curbs. Saudi Arabia cut term supplies to some Asian refiners by as much as 40% and Iraq said it will make deep reductions.

Brent crude has rebounded rapidly since April as the OPEC+ production cuts kicked in and U.S. production fell. While the rally fizzled out last week over fears of a second coronavirus wave, physical crude markets in Europe have continued to strengthen. A White House plan to spend nearly $1 trillion on infrastructure could be positive for prices if it materializes.

“Massive stimulus around the world will stimulate a rebound,” said Bjarne Schieldrop, chief commodities analyst at SEB AB. “Equities higher, oil price higher. All on the up.”

Prices:

- West Texas Intermediate crude for July delivery rose 2% to $37.85 a barrel as of 12:40 p.m. in London

- Brent for August delivery added 2.1% to $40.55 a barrel

In a sign that U.S. fuel demand may be improving, gasoline futures are once again rallying when massive oil refineries shut down. Houston gasoline climbed to a three-month high Monday after Motiva Enterprises LLC shut a key unit at the largest U.S. refinery in Port Arthur, Texas. Meanwhile, shale production is still in retreat, with the Energy Information Administration forecasting it will fall further next month.

OPEC and its allies have agreed to maintain production cutbacks amounting to about 10% of global supply through next month, and will hold committee meetings on Wednesday and Thursday to assess their impact. So far this month, shipments from Saudi Arabia have remained muted, with flows to the U.S. dropping dramatically.

Other oil-market news

Oil-production limits adopted by OPEC+ will soon bring prices back to “normal,” according to the oil minister from the United Arab Emirates.

The coronavirus has exposed the fragility of some of the world’s biggest oil and gas companies, but also given them the opportunity to make investors swallow some unpleasant remedies.

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Japan’s Inpex said on Tuesday it has completed previously launched refinancing of part of the funding for its Ichthys liquefied natural gas export project in Australia.

The refinancing deal includes a portion of the project finance loans arranged in 2012 with export credit agencies and commercial banks. It includes loan conversions and improved borrowing conditions.

Inpex said it launched the refinancing in March after Ichthys LNG achieved financial completion in December 2019 and was now continuing stable production.

“The project’s smooth progress despite the impact of the decline in oil prices caused by the spread of Covid-19 and other factors was evaluated favorably”, Inpex said.

Total project finance loans amount to about $15.6 billion, of which the refinancing amount covered in the refinancing agreement is about $8.3 billion.

The deal involves seven export credit agencies and 28 commercial banks.

Inpex said the refinancing deal would boost the value of the project by reducing the financial commitment of Ichthys LNG.

Furthermore, the deal is part of Inpex’s cost reduction initiatives in response to the decline in oil prices and the company sees the deal improving the resilience of its business structure.

The Ichthys project produces LNG at the 8.9 million tonnes per year plant at Bladin Point near Darwin.

Natural gas arrives in Darwin from the giant Ichthys field offshore Western Australia via an 890-kilometre export pipeline.

Ichthys LNG is a joint venture between operator Inpex, major partner France’s Total, and the Australian units of CPC Corporation Taiwan, Tokyo Gas, Osaka Gas, Kansai Electric Power, JERA and Toho Gas.

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Petrol and diesel prices were hiked in metros on Tuesday, marking the tenth straight day of increase since state-owned oil companies returned to the normal practice of daily reviews following a 12-week pause. With effect from 6 am, the prices of petrol was increased by 47 paise per litre and diesel by 57 paise per litre in Delhi, compared to the previous day. While the price of petrol was revised to Rs 76.73 per litre in the national capital from Rs 76.26 per litre the previous day, the diesel rate was increased to Rs 75.19 per litre from Rs 74.62 per litre, according to notifications from state-run Indian Oil Corporation, the country's largest fuel retailer. In the ten-day period, the price of petrol has been increased by a cumulative Rs 5.47 per litre, and diesel by Rs 5.80 per litre. (Also Read: How To Find Latest Petrol, Diesel Rates In Your City)

Here are the current petrol and diesel prices in metros (in rupees per litre):

Crude oil futures erased early gains amid persistent doubts over whether supply cuts would be enough to reduce an oil glut. Brent crude futures - the global benchmark for crude oil - were last seen trading down 1.2 per cent at $39.23 per barrel.

State-run oil marketing companies revise the prices of petrol and diesel from time to time, besides aviation turbine fuel (ATF) - or jet fuel - and liquefied petroleum gas (LPG). However, since March 16, the oil companies had kept petrol and diesel prices on hold, possibly due to the volatility in global oil markets.

Fuel retailing in the country is dominated by state refiners - Indian Oil Corporation, Bharat Petroleum Corporation and Hindustan Petroleum Corporation. The three own about 90 per cent of the retail fuel outlets in the country.

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Increased cases of Covid-19 and weak economic data hitting crude oil, reports Phil Flynn.

Sunday night is always a good time for markets to overreact after a pause in global trading. A wave of crude oil and stock selling on fears of a second wave of the Coronavirus permeated the trade. The market is pricing in the odds of another lock down of global economies, thereby taking away the oil demand gains that we have seen in recent weeks.

China, ground zero for the start of the Coronavirus, accentuated those concerns. After nearly two months with no new infections, Beijing officials have reported 79 new Coronavirus cases over the past four days, according to Reuters. We also saw increases in disease in parts of the United States and Japan as well. Yet is it too early to predict a massive second wave?

It’s too early to predict another shutdown of the global economy. Oil also should focus on what seems to be a better outlook when it comes to a rebalancing of global oil supply.

We saw, for example, another increase in China’s industrial output for the second month in a row in May. Chinese refinery runs also spiked by 8.2% to an impressive 13.6 million barrels a day.

We see better compliance with the most significant OPEC Plus production cut in history, which increases the odds that the reduction will be extended until the end of the year. The cut that had reduced 10% of the global supply was in jeopardy due to some noncompliance. The biggest offender was Iraq, and both Russia and Saudi Arabia exerted pressure on the country to get their oil production under control.

Reuters is reporting that is happening. They wrote, “Iraq has agreed with major oil companies operating its giant southern oilfields to cut crude production further in June, Iraqi officials working at the fields told Reuters on Sunday. Baghdad aims to improve its compliance with its output cut targets under a global deal with OPEC and its allies to reduce the oil supply. Iraq has agreed with Russia’s Lukoil PAO (LKOH) to start an additional cut of 50,000 barrels per day (bpd) as of June 13 to lower production from the West Qurna 2 field to around 275,000 bpd. Lukoil cut output by 70,000 bpd in May in response to a request by Iraq’s oil ministry; two Iraqi oilfield managers told Reuters on Sunday. Production from West Qurna 2 was around 395,000 bpd in April, the managers said.”

The Iraqi oil managers, who oversee production operations, said state-run Basra Oil Company had asked BP (BP) to cut production from the Rumaila oilfield by around 140,000 bpd of its total production, which stands at between 1.4 million bpd to 1.45 million bpd. Exxon Mobile Corp. (XOM) has also agreed to cut an additional 70,000 bpd from the West Qurna 1 field to reduce production to around 350,000 bpd in June, the two Iraqi managers said. Production was cut by about 50,000 bpd in May and stood at approximately 420,000 bpd. Lukoil, B.P., and Exxon were not immediately available for comment. Iraq has told OPEC it would start an urgent plan to cut its oil production gradually to fully comply with its quota after the group demanded that Baghdad and other laggards adhere to a pact on output curbs.

BP is anxious about the future of oil demand. The Wall Street Journal reported that, “BP PLC is writing down up to $17.5 billion of its assets and might leave some of its oil and gas in the ground because of lower energy prices and weakened demand amid the global crisis caused by the novel Coronavirus. The British energy giant sees the pandemic—which caused nationwide shutdowns and drove U.S. oil prices into negative territory—having a lasting economic impact, leading to fragile energy demand and sinking prices. The virus will also accelerate the world’s shift to a lower-carbon economy, BP said, with governments directing some of their stimulus packages to climate-friendly initiatives. BP’s shares were down 4% in early trading Monday. The company expects to report its second-quarter results on Aug. 4, a week later than previously planned.

The largest write-down by an oil major in years is also linked to BP’s newly appointed chief executive’s plans to reshape the company. Bernard Looney, who was promoted in February, wants to prepare for a low-carbon future by making B.P. leaner and nimbler. Last week, BP said it was cutting nearly 10,000 jobs, or 14% of its workforce, as it seeks to strengthen its finances. That followed a move by Chevron Corp. to cut its workforce by up to 15%.

Gas demand is coming back and so are gasoline prices. The A.P. reported that, “The average U.S. price of regular-grade gasoline rose 11¢ over the past two weeks, to $2.16 per gallon. Industry analyst Trilby Lundberg of the Lundberg Survey says Sunday that the jump came as crude oil costs increased. The highest average price in the nation for regular-grade gas is $3.11 per gallon in Honolulu. The lowest average is $1.69 in Baton Rouge, Louisiana. The average price of diesel is $2.55, the same as two weeks ago.

Rbob futures look solid as demand is coming back. The second wave fears may pause us, but Rbob should have a great week. It should also help the oversupplied distillate market.

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Dubai — Stockpiles of oil products at the port of Fujairah in the UAE dropped for a second consecutive week amid signs of a rebound in trading.

Stockpiles stood at 30.113 million barrels as of June 15, down 1.3% on the week, after falling 0.7% a week earlier, data from the Fujairah Oil Industry Zone showed on June 17. Stockpiles had been climbing to record highs for most of May and early June as the coronavirus pandemic curbed demand for gasoline, jet fuel and marine bunkers.

At Prostar Capital, which owns two storage companies in Fujairah, movement of crude oil and products in and out of terminals dropped 35% in February and March, and is now about 10% below the January turnover, Tony Quinn, operating partner of Prostar in Singapore, said.

"I would say in another month we'll be back to normal volumes in terms of throughput," Quinn said. "The first pick-up was in China toward mid-May, and we're seeing more volumes to China, which has helped Fujairah as well.''

He estimated Prostar's jointly owned Fujairah storage companies -- Fujairah Oil Terminal and GTI Fujairah -- account for about 20% of Fujairah's independent crude oil and refined products storage.

Light distillates, which include gasoline, naphtha and other light petrochemical feedstock, slipped 10% week on week to 7.487 million barrels, the biggest decline since the week ended May 4.

"The East of Suez gasoline market continued to find support as the gradual process of easing domestic movement restrictions continued, leading to signs of a demand recovery across various countries," Platts reported in a June 17 commentary on inventories.

Middle distillates, which include jet fuel, kerosene, gasoil and marine bunker gasoil, jumped 10% on the week to 5.536 million barrels, resuming gains for the 11th time in 12 weeks.

Heavy distillates and residues, which include fuels for marine bunkers and for power generation, fell less than 1% week on week to 17.09 million barrels, after hitting a record high a week ago.

Stockpiles of both middle and heavy distillates hit all-time highs earlier this month, while stocks of light distillates are well below the record high 11.975 million set on January 28, 2019, according to the data compiled by Platts, which is the official publisher of Fujairah's inventory data.

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Saudi Arabia is significantly cutting its crude oil exports to the United States this month, with shipments likely to hit a 35-year low and reducing the overhang in U.S. oil inventories, Bloomberg reported, citing tanker-tracking data that it has compiled.

The drastic cut in Saudi crude oil exports to the U.S. is a radical shift from the Kingdom’s tactics from two months ago, when it sent a fleet of supertankers to flood the U.S. market with oil during the price war with Russia at the end of March and early April. Back in April, the tanker fleet from Saudi Arabia coincided with the massive oil demand loss and threatened to overflow U.S. storage capacity.

But after Saudi Arabia and Russia forged a new pact to cut a record amount of OPEC+ production to support oil prices, the Saudis now look intent to help reduce U.S. inventories by withholding supply to the U.S., the market which reports crude oil inventories every week.

According to tanker shipping data compiled by Bloomberg, in the first half of June, Saudi Arabia sent just one cargo of crude to the United States, equal to around 133,000 barrels per day (bpd). This compares to an estimated 1.3 million bpd of Saudi oil shipped to the United States in April. Related: Exxon Forced To Curtail Production In Guyana

Some Saudi tankers haven’t signaled their final destination yet, but if the pace of Saudi crude exports to the U.S. continues for the rest of June, they would hit the lowest in 35 years and help draw down some of the U.S. inventories which are sitting at above the five-year range because of the lost demand during the lockdowns.

Last week, the EIA reported a rise in U.S. crude oil inventories of 5.7 million barrels for the week to June 5 and an increase in fuel inventories.

At 538.1 million barrels, crude oil stocks were at a record high, and way above the five-year range for this time of the year. To compare, at this time last year, U.S. commercial crude inventories were 485.5 million barrels. U.S. gasoline demand averaged 7.9 million barrels per day in the week to June 5, up from 7.55 million bpd in the prior week, but still well below the 9.877-million-bpd demand for the same week a year ago, according to EIA data.

https://oilprice.com/Energy/Crude-Oil/Saudi-Arabias-Oil-Exports-To-The-US-Set-To-Drop-To-35-Year-Low.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNGxgBBVXC3TS7DHMUwCjfNc2Mj9p

The fossil fuel industry has faced serious headwinds for several years, but the rise of renewables combined with the fall in consumption as a consequence of the global corona crisis is pushing it over the edge and into “terminal decline”. Although global coal consumption continues to grow slowly, its use has peaked in developed regions. According to the 2019 BP Statistical Review of World Energy, U.S. coal consumption fell by more than 40% in the past decade, while in the EU it has seen a nearly 27% drop.

The primary culprits behind coal’s decline are competition from cheap natural gas brought on by the shale gas boom in the U.S., as well as a surge of renewable capacity aided by legislation aimed at curbing carbon dioxide emissions.

Victims of Their Own Success

But the natural gas and subsequent oil boom were victims of their own success. Even though demand growth for both of these commodities has been robust over the past decade, prices have plunged. So while it’s unsurprising that the coal industry has suffered immense financial stress over the past decade, the same is true of the oil and gas industry. Despite strong demand growth for its products, the prices of oil and natural gas have fallen by more than 50% in recent years.

The fossil fuel industry has faced an oversupply problem, as well as a public relations problem. Even before the COVID-19 pandemic, the industry was already seen by many as one on its way out, and therefore it struggled to attract investors. Nevertheless, it seemed likely that the industry would enjoy at least another decade of dominance before renewables and electric vehicles combined to put the industry into permanent decline.

COVID-19 Rapidly Changed the Outlook

But COVID-19 has caused a significant change in the industry outlook. In the early stages of the pandemic, China’s economy slowed as the country grappled to contain the virus. This slowdown had a negative impact on fossil fuel demand. As oil demand began to soften, OPEC tried to work with Russia to reduce production. Talks failed, a subsequent price war broke out between Saudi Arabia and Russia, and oil prices collapsed. Related: India Looks To Double Oil Refining Capacity By 2030

As COVID-19 spread to other countries and quarantines were implemented, oil prices ultimately fell into negative territory, which had never happened before with a major benchmark. Power demand fell as businesses closed and people stopped travelling or commuting. This created a perfect storm that obliterated fossil fuel demand in April. Global oil demand fell by as much as 30 million BPD, followed by gas and coal demand. Even demand for liquefied natural gas (LNG), which has seen strong growth in recent years, plummeted, and cargos destined for Asia had to be rerouted to Europe, adding to a supply glut there.

Meanwhile, renewables may see a small negative impact from the pandemic in the short term – but the move toward green energy may gain momentum as the COVID-19 threat fades. Underlying demand for clean energy is rising. Further, the investment climate for fossil fuels will continue to worsen over time, so the industry may find itself struggling to attract new capital even after the crisis.

A Place for Nuclear Power

However, existing infrastructure of fossil fuels will create some headwinds for renewables, as well as nuclear power, the world’s largest source of low-carbon energy. The industry will hardly give up its primacy without a fight.

What this looks like can be observed in Lithuania, which had placed its chips on a new LNG terminal in 2014 to reduce the country’s dependence on Russian gas. However, the Klaip?da terminal was never profitable, and to this day operates at only a fraction of its capacity while incurring costly maintenance fees shouldered by gas consumers. To curb its losses, Klaip?da now receives LNG cargoes from Russia too.

Part of the problem is that the LNG market price was already depressed before the COVID crisis. In 2015, when the terminal went online, the price was lower than the price Lithuania paid to Statoil, which forced the state to levy high terminal fees to cover for the losses from selling gas. Now, with the pandemic having further collapsed fossil fuel prices, the fees are going up accordingly, with no contribution to energy security. Related: Oil Markets May Not Fully Recover Until 2022

The decision to bank on LNG under these circumstances is seen as one of the factors leading Lithuania to campaign against a nuclear power plant in Astravets in neighbouring Belarus. Besides constantly questioning the plant’s safety – contrary to international assessments – Lithuania has passed laws prohibiting the purchase of energy from Belarus after the power plant begins operations later this and next year. Furthermore, Lithuania is aggressively lobbying Brussels and other capitals in the region for a full boycott of electricity imports from Belarus. If implemented, this could lead to millions of additional CO2 emissions in the region.

The New Energy Order?

The fact remains that the world could find itself with an energy shortfall if the crisis is long-lasting and fossil fuels disappear faster than originally expected. That could hit the power sector because of falling coal and natural gas production, at a time that global demand for electric vehicles is growing.

Nuclear power can be part of a low-carbon sustainable future along with renewable energy. Indeed, the International Energy Agency estimates that in order to meet the world’s sustainability targets the current rate of nuclear capacity additions, which is about 10-12 gigawatts of electricity (GWe) per annum, must be at least be doubled. With the current crisis impacting the fossil fuel sector, capital budgets are being slashed. That implies a decline in output, which could be larger than the capacity of variable renewables to absorb. The current glut of energy supply may turn into a series of severe intermittent shortages when sun doesn’t shine, and wind doesn’t blow.

Although it would be premature to suggest that the current pandemic marks the end of fossil fuels, it might not be a stretch to call this the beginning of the end. It’s important to focus on the overall system performance and ensure that the transition to a low carbon future is sustainable itself.

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LONDON (ICIS)--OPEC has cut expected crude demand for its member states this year amid a modest uptick in non-OPEC supply growth forecasts.

The cartel expects demand for crude for its members to stand at 23.6m bbl/day this year, a reduction of 700,000 bbl/day from forecasts last month, despite leaving overall global demand projections unchanged at minus-9.1m bbl/day.

Non-OPEC liquids production is expected to increase by 300,000 bbl/day compared to cartel forecasts last month, driven by Norway, Brazil, Guyana, and Australia.

Global oil production is still expected to fall substantially in the second half of the year as demand collapse and weak economies drive down output beyond the OPEC+ production cuts, the cartel said.

Non-OPEC supply is expected to fall 6.1m bbl/day year on year in the second half of 2020 compared to 1.8m bbl/day in the first, on the back of production curtailments by players such as Russia that have signed on to the cartel’s output cut agreements, as well by declines elsewhere, particularly North America, according to OPEC.

Weak oil pricing and a producer focus on capital discipline are likely to drive sharp declines in the US shale sector and Canada’s Alberta oil sands mean that the region is likely to lead the production falls forecast for the second half of the year, with combined falls of 2.8m bbl/day.

Non-OPEC industry capital expenditure is expected to fall 30% this year compared to 2019, representing a drop of $138bn to stand at $321bn.

OPEC production fell 6.3m bbl/day month on month in May, according to secondary sources, as the latest round of production cuts came into effect, a dramatic fall but substantially below the stated target of a 9.7m bbl/day cut, in addition to an additional voluntary cuts by Saudi Arabia and some other Middle Eastern partners.

The Kingdom accounted for almost half of the cuts, slashing output by 3.16m bbl/day, and all other members cutting output with the exception of Iran.

The partners to the accord agreed to extend the deepest cuts another month to July, but the window remains relatively narrow for producers to adjust production to the extent outlined in the deal.

The market has reacted positively to the introduction of the cuts at the start of May and to plans to extend the period the deepest cuts would be in place, but the road to recovery from the lows of April-May is expected to be a long one, according to OPEC.

“Increasing global crude oil prices in futures markets since the beginning of May reflect the perception of an earlier-than-expected recovery in oil demand amid a reduction in supply due to global production shut-ins,” OPEC said in its monthly oil report.

“Nevertheless, it remains to be seen whether US upstream investment can recover in the short term from the current deep cuts due to the COVID-19 pandemic and subsequent drop in oil prices,” the group added.

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Tokyo — Gasoline demand in Japan is showing signs of recovery following the lifting of the state of emergency, prompting the country's largest refiner, JXTG Nippon Oil & Energy, to snap up at least one MR-sized gasoline cargo from Singapore, believed to be the first purchase from overseas in months.

JXTG bought one gasoline cargo loading in June in Singapore, a source familiar with the matter said June 17, without giving further details.

A spokeswoman for JXTG Nippon Oil & Energy on June 17 declined to comment on specifics of its product deals.

JXTG's purchase comes on the heels of a larger than expected domestic demand recovery for gasoline in recent weeks following the lifting on May 25 of the state of emergency, which was declared April 7 to curb the spread of the coronavirus pandemic.

Trafigura will use its own ship, the Olaf, for loading a 35,000 mt cargo in June for Kawasaki delivery, shipping brokers said. The Olaf, which is in Singapore, is scheduled to arrive in Kawasaki on June 25, according to S&P Global Platts trade flow software cFlow. Trafigura executives could not be immediately reached for comment.

Currently, JXTG's 235,000 b/d Kawasaki refinery is shut for scheduled maintenance work. The 65,000 b/d No. 3 crude distillation unit at Kawasaki is due to be restarted in late June, with the 170,000 b/d No. 2 CDU restarting in early July.

Net importer in April

JXTG last bought at least one spot MR-sized gasoline cargo loading in April from South Korea when Japanese refiners were increasingly cutting runs as the coronavirus pandemic eroded domestic oil demand, as well as the import economics for product from the country.

Together with increased imports by Cosmo Oil, Japan was a net importer of gasoline in April as refiners raised oil product imports from neighboring countries because of refinery run cuts in response to plummeting domestic demand.

Japan imported an average of 68,571 b/d of gasoline in April, more than triple the 19,569 b/d a year earlier, and flipped to being a net importer after exports came to 44,856 b/d, according to the Ministry of Economy, Trade and Industry data.

At the start of June, however, Japan's crude throughput rose for the first time in seven weeks, with domestic gasoline demand recovering to pre-state of emergency levels.

Japan's estimated gasoline shipments rose 3.8% week on week to 5.23 million barrels in the June 7-13 week, staying above the pre-state of emergency level of 4.72 million barrels over April 5-11, according to calculations by Platts based on Petroleum Association of Japan data.

On June 17, Japan's domestic gasoline rack prices in Chiba, east of Tokyo Bay, stood at Yen 37,300/kiloliter ($55.21/b), up 33% or Yen 9,200/kiloliter from May 25 when the state of emergency was lifted, Platts data showed.

Regional recovery

Japan's demand recovery follows a trend in the wider Asian gasoline market, which has been heavily supported of late by an uptick in driving activity in the region.

The latter has especially seen sustained growth since mid-May, with most Southeast Asian countries such as Malaysia, Vietnam, Cambodia and Myanmar easing lockdowns and reopening their domestic economies.

Even Singapore -- the region's oil trading hub -- is set to move into its next phase of easing on June 19, after having been in partial lockdown since mid-March.

Against the backdrop of improved demand, supply-side fundamentals have similarly recovered, with China and South Korea having lowered their export volumes in May and June.

"We are seeing a converging demand-supply dynamic now. Supplies are not tight but the amount of replacement barrels is not as much," a Singapore-based trade source said.

"Vietnam is coming out to buy, and without South Korean barrels, they are forced to take the cargoes from alternate sources such as Singapore," a second source said.

Reflecting the supported fundamentals, the FOB Singapore 92 RON gasoline crack against front-month ICE Brent crude futures was assessed at plus $4.07/b at the close of Asian trade on June 17, sharply higher than the minus $1.46/b it had averaged in May, Platts data showed.

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Washington — US driving demand is picking back up among commuters and commercial trucks, but it may be too soon to expect rates to return to pre-lockdown levels given potential long-term remote working, the shaky economic outlook and rising infection rates in several major demand states.

Kayrros found in a recent analysis that gasoline demand from commuters and other light vehicles has seen a mostly uniform rebound from sharp lows in April, even in states with the longest lockdown restrictions.

"Today we're back up to levels of driving demand for regular drivers that we would see in a seasonal low and during the holidays," said Ted Hall, Kayrros' vice president for market strategy.

However, diesel demand from long-haul trucking appears to be stagnating, even though it never plummeted like commuting did when governors ordered residents to stay at home. Hall said the lows for trucking demand were equivalent to January slowdowns when truckers take time off after the holidays.

Hall said this slower recovery for trucking could be an indicator of economic trouble ahead.

"If we're being optimistic, there's a lag effect where once regular activity resumes then commercial activity will come on," he said. But "the concern here is that might be an early indicator that the economy isn't coming back quite in the way we were hoping."

Weekend, summer miles

Gary Eisen, an economist for S&P Global Platts Analytics, said rebounding driving trends seen in Inrix and Apple Mobility data indicate that either commuting is returning stronger than expected or that drivers are doing more discretionary trips since being cooped up while working from home.

Eisen estimates that travel to and from work typically accounts for roughly 30% of US driving demand. Record low unemployment numbers have eased in recent weeks, with payrolls seeing an unexpected increase in May.

"One of the things that's striking is weekday travel hasn't picked up that much," Eisen said. "It's better than where it was in April but a fraction of what has happened to weekend demand."

Eisen said last summer's surge in air travel without any corresponding boost to driving demand could lead to a bump in vacation driving this summer as Americans shun airplanes but still want to get away.

"I do believe we're going to get a boost this summer from that source," he said. "That will be another part of the story."

Platts Analytics estimates US gasoline demand sank to 5.9 million b/d in April during peak lockdown restrictions before rising to 7.2 million b/d in May and 8.8 million b/d by December. It sees US gasoline demand averaging 8.1 million b/d in 2020, down from 9.3 million b/d in 2019.

Diesel roadblock

The US diesel demand outlook has been hard to pin down because of temporary surges in demand this spring such as for shipping medical supplies early in the outbreak and then planting season in farm country.

"Trucking was fine and then it all of a sudden fell off a cliff," Eisen said. "All of these temporary props to demand suddenly disappeared. Now you're looking at this dark possibility you're going to see numbers in the 3.4 million b/d range."

For now, Platts Analytics estimates US distillate demand bottomed out in April at 3.4 million b/d and will stay around 3.7 million b/d through September. It sees US distillate demand averaging 3.9 million b/d in 2020, down from 4.1 million b/d in 2019.

Outbreak risks

Rising infection rates in several states in the past week also present major risks to recovering US oil demand.

California, Texas and Florida -- the three top US gasoline demand states -- plus Georgia, Louisiana and North Carolina have seen coronavirus cases increase by at least 40,000 in the past two weeks.

The six states accounted for 3.3 million b/d in gasoline demand before the crisis, or 35% of overall US demand, according to US Energy Information Administration data.

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NEW YORK (Bloomberg) --Oil slid after U.S. petroleum inventories climbed to a record for the second week in a row, more than offsetting signs of a recovery in fuel demand.

Gasoline and distillate inventories fell last week, according to a report from the Energy Information Administration, reflecting a slight pick-up in demand during the summer driving season with coronavirus-led lockdowns easing in some parts of the U.S. Stubbornly high crude inventories still threaten to cap crude’s rally from historic lows in April.

“The distillate draw is a clear sign of the reopening of the economy and transportation returning,” said Rob Thummel, portfolio manager at Tortoise. “We still need to see inventories come down. That’ll be the catalyst for oil prices to move higher.”

Prices:

- West Texas Intermediate for July settlement slipped 42 cents to settle at $37.96 a barrel in New York.

- Brent for August delivery fell 25 cents to settle at $40.71 a barrel on the ICE Futures Europe exchange.

- In the U.S. physical market, price differentials to futures were little changed.

In a note on Wednesday, Toronto Dominion Bank’s commodity strategist head Bart Melek said “a sustained re-balancing will require ongoing demand growth, which could be challenged by waves of new infections across much of southern USA.”

Earlier in the day, OPEC predicted that fuel demand will remain “under pressure” during the second half of the year because of the ongoing economic fallout from the coronavirus.

Saudi Arabia, Russia and other members of the OPEC+ coalition are due to hold an online meeting on Thursday to review the impact of the biggest ever production cuts announced.

The EIA report showed that U.S. crude production fell by 600,000 barrels a day to 10.5 million, the lowest since 2018. While that would appear quite bullish, last week’s data coincided with the passage of Tropical Storm Cristobal, which forced some producers to shut output in the Gulf of Mexico.

Other oil-market news:

- Growth in energy demand was declining even before the coronavirus pandemic spread globally, keeping consumers under lockdown and sending prices to record lows, BP Plc said Wednesday.

- Global oil demand is back to about 90% of its pre-coronavirus level, according to top commodity trading house Trafigura Group, which three months ago was among the first to sound alarms about the rapid drop in consumption due to the outbreak.

- Saudi Aramco has suspended work at two offshore drilling rigs for about a year, according to filings from the contractors. The producer is also delaying a related $18 billion oil and gas expansion project by at least six months, according to people with knowledge of the situation.

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The rebalancing of the oil market has been possible, in part, due to the sharp cutbacks in U.S. shale production. But what happens next for the industry?

The latest data from the EIA estimates that production plunged by a colossal 600,000 bpd in the week ending on June 12, a massive decline that puts output down more than 2.6 million barrels per day (mb/d) from the weekly peak hit in mid-March (to be sure, monthly EIA data shows the U.S. hit a slightly lower peak in November 2019).

At the same time, the industry is bringing shuttered production back online. Reuters says that 500,000 bpd of shut-in production could be restored by the end of June. For instance, Devon Energy shut in about 10,000 bpd in recent weeks, but is “in the process of bringing all of that back on,” Devon Energy CEO David Hager said at a JPMorgan conference on Tuesday, according to Reuters.

Analysts have varying perspectives on what happens next for shale drilling. According to Morgan Stanley, the industry will proceed in three phases. First, shut-in wells come back online. Then production stabilizes, but an average of $40 per barrel will be needed for that to occur. Finally, production growth resumes, assuming prices move back up to $50 per barrel.

However, there is “little room for US production to grow this year or next,” Morgan Stanley cautioned, noting that if output began to rise, it would merely derail the oil price rally. The capex cuts announced to date should translate into production declines of 1.8-1.9 million barrels per day by the end of 2020, compared to the end of 2019.

The bank said that the shale industry will need two years or so of WTI averaging at least $50 per barrel in order for shale output to rebound to pre-Covid 19 levels. “Some level of growth would likely come back quickly in the first year, and moderate thereafter without higher investment due to the reversal of temporary cost reductions, depletion of drilled-but-uncompleted (DUC) well inventory, and rising base declines,” the bank concluded.

JBC Energy forecasts WTI averaging $40 per barrel for the rest of the year. “Under this assumption we see completed wells having reached their nadir of below 200 in May with a gradual recovery to 700 by the end of the year and 1,000 by end-2021,” the firm wrote in a note.

If prices actually averaged between $45 and $50 per barrel, which would require better compliance from OPEC+ to their cuts, then it would be a “turning point” for U.S. shale, the firm argued. Shale output would reach an “inflection point” in November 2020, and see a “swift recovery thereafter,” JBC said. A year later, U.S. shale output would be back to pre-pandemic levels.

That is a more optimistic scenario. JBC’s base case calls for U.S. shale to take until September 2023 to return to peak production levels last seen earlier this year. But “[c]onsidering current sentiment…we would tend to see the risk to our shale supply base case skewed to the upside,” JBC wrote.

Others are more pessimistic, noting that both oil and broader financial markets are getting a little frothy. “[T]he rally across commodities has gotten ahead of fundamentals with the exception of metals,” Goldman Sachs wrote in a June 9 report.

They are not alone. “We think the oil market is not currently pricing in a significant probability of either second waves of coronavirus cases in key consumers and the associated lock-downs, or anything less than a rapid return to economic business-as-usual,” Standard Chartered wrote in a June 16 report. “We think this absence of shades of grey represents a downside risk to prices medium-term, but short-term, unnuanced hope is proving to be a powerful force supporting prices.”

The bank went on to criticize media representations of the oil market as “tight,” adding that “[w]e do not think a market with more than a billion barrels of excess inventories and more than 10 million barrels per day (mb/d) of spare capacity in OPEC+ can be described as tight.” While global supply may fall below demand in the coming months, it would take roughly two years to bring inventories back to the five-year average, the bank noted.

Meanwhile, many U.S. shale companies are drowning in debt. Just a few days ago, Extraction Oil & Gas, a large shale driller in Colorado, declared bankruptcy. Chesapeake Energy, which arguably best represents the debt-driven shale bonanza, is expected to file for bankruptcy any day now. The Chapter 11s, and even the “Chapter 22s” – a nickname for those that are set to declare bankruptcy for the second time – are expected to continue to rise.

All the while, steep decline rates will likely more than overwhelm any new drilling that takes place. Oil prices have bounced off of April lows, but U.S. shale is far from a comeback.

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