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Oil prices rose about 1%, with global benchmark Brent settling at a two-week high in volatile trade on Tuesday as traders worried about tight supplies and a weaker dollar.

Brent futures rose $1.08, or 1.0%, to settle at $107.35 a barrel. U.S. West Texas Intermediate (WTI) crude rose $1.62, or 1.6%, to settle at $104.22.

Brent posted its highest close since July 4 and WTI its highest since July 8. At one point during the volatile session, both benchmarks were down around $2 a barrel.

“Crude oil has staged an incredible turnaround today,” said Robert Yawger, executive director of energy futures at Mizuho.

“There was no big red bullish headline to greenlight the rally, but the combination of beaten down open interest and low trade volume will often encourage wild price swings,” Yawger said.

The U.S. dollar

Oil prices have whipsawed, supported by supply fears due to Western sanctions on Russia, but pressured by global central bank efforts to tame inflation which stoked fears that a potential recession could cut energy demand.

On Friday, open interest in New York Mercantile Exchange futures fell to the lowest since September 2015 as investors cut risky assets like commodities, worried that the Federal Reserve will keep raising U.S. interest rates.

The U.S.-Canada Keystone pipeline was operating at reduced capacity on Monday after a pump station was shut.

Libya’s new National Oil Corp (NOC) chief Farhat Bengdara rejected challenges to his appointment and work resumed at some shuttered fields and ports.

The U.S. 3:2:1 and gasoline crack spreads – measures of refining profit margins – both fell to their lowest since April.

“Crack spreads continuing plunge of past four weeks to narrowest level since late April … suggesting weakening product demand,” said analysts at Ritterbusch and Associates, a consultancy.

Last week, U.S. President Joe Biden visited top oil exporter Saudi Arabia, de facto leader of the Organization of the Petroleum Exporting Countries (OPEC), whose crude exports slipped in May to a four-month low.

Biden hoped to strike a deal on an oil production boost to tame fuel prices, but the kingdom’s foreign minister said the market’s problem was not a crude shortage but a lack of refining capacity.

In the United States, expectations for an increase in crude inventories weighed on prices. Analysts polled by Reuters forecast crude inventories rose by 1.4 million barrels last week.

The American Petroleum Institute (API), an industry group, will issue its inventory report at 4:30 p.m. EDT (2030 GMT) on Tuesday. The U.S. Energy Information Administration (EIA) reports at 10:30 a.m. EDT (1430 GMT) on Wednesday.

On Tuesday, people familiar with Biden’s plans told Reuters that the president plans to announce new federal measures aimed at the climate crisis on Wednesday.

Early in the session, oil prices fell on weak economic data from around the world.

Reuters by Scott Disavino, July 26, 2022

Here’s a thought: fuel shortages wouldn’t be as severe as they are today had bureaucrats not thrown a spanner in the works of two long-delayed LNG terminals.

One may be tempted to cite the recent defaults by LNG suppliers under long-term contracts alongside record-high prices on the spot market to declare that the need for more LNG terminals has become moot.

But before leaping to conclusions, consider the following: it’s not sovereign-backed Qatar Energy that’s been defaulting on long-term contracts; rather the international trading houses — Eni and Gunvor — that have defaulted on promised cargoes and messed up the country’s power sector.

One of the two planned terminals is backed mainly by Qatar and has three local industrial groups as minority shareholders. After six years of navigating the regulatory rigmarole, the terminal is still a distant dream.

Had the terminal received the promised pipeline capacity from Sui companies in time, it would’ve been importing Qatari gas under long-term contracts already, for onwards sale to the local industry, without the need for any sovereign guarantees.

The other planned terminal is wholly owned by Mitsubishi Corporation, one of the most influential players in the global energy market. No LNG trader in the world would’ve defaulted on its cargoes because the Japanese player is responsible for more than half the LNG imported every year by Japan, one of the biggest gas importers worldwide.

Impact of Ukraine war

Pakistan began importing LNG in 2015 as domestic gas reserves started depleting at a faster pace. The country has already installed two terminals on Port Qasim. Pakistan State Oil Company Ltd uses the Engro Elengy Terminal to import gas under long-term contracts, while Pakistan LNG Ltd brings spot purchases through the GasPort LNG Terminal.

Less than 50 per cent of annual LNG imports are through the spot market, where prices skyrocketed after the Russian invasion of Ukraine on Feb 24. Little wonder that no bidder responded to the latest tenders by Pakistan LNG Ltd for 10 cargoes. Before that, the state-owned company made three unsuccessful attempts to buy LNG in July.

As for the four long-term contracts meant to bring more than half of the country’s total LNG imports at substantially lower than spot rates, there have been constant defaults by global suppliers.

Since the beginning of 2021, Eni has defaulted on at least four cargoes while Gunvor has defaulted on at least seven, according to data compiled by the Institute of Energy Economics and Financial Analysis.

Force majeure or not?

Pakistan reserves the right to impose a penalty on defaulting suppliers equalling 30pc of the cargo cost. Suppliers invoke force majeure — unforeseeable circumstances preventing them from fulfilling the contract — to avoid paying the penalty.

“Long-term contracts must always require the supplier to disclose the fuel source and the vessel’s name. Otherwise, what’s stopping it from selling the cargo on the spot market whenever the rate is high enough to justify a default on long-term deliveries?” said an energy expert with many years of LNG procurement experience for European employers.

It’s difficult to invoke force majeure on a false pretext if the long-term buyer knows the source of LNG and the vessel that’s supposed to deliver it.

The developers of both upcoming terminals have repeatedly asked the government to allocate at least 300 million cubic feet per day (mmcfd) of pipeline capacity each before they take the final investment decision (FID), however, there has been little tangible progress from the state-owned gas utility companies on the allocation of pipeline during the past few years.

Qatar-backed Energas LNG and Mitsubishi-backed Tabeer LNG have capacities of 750-1,000mmcfd each. Given the capacities of the already-operational Engro Elengy (690mmcfd) and GasPort LNG (750mmcfd), the addition of the two “merchant” terminals can more than double the country’s re-gasification capacity.

They will also increase the country’s LNG storage capacity, which currently stands at 320,000 cubic metres.

Pakistan is one of the top seven LNG importers globally, yet it ranks as low as 18th in terms of storage capacity.

As a matter of fact, the country uses the existing Floating Storage and Re-gasification Units (FSRUs) of the existing two terminals merely as re-gasification units. This means the system relies heavily on the gas line-pack, which is the volume that can be stored in a pipeline for scheduling purposes.

According to a July 4 report by Reuters, Germany has leased as many as four FSRUs in a bid to quickly diversify away from Russian energy. “But here, foreign investors have been running from pillar to post for years just to get the promised pipeline capacity,” said the energy expert.

DAWN by Kazim Alam, July 27, 2022

The United States is shipping record volumes of liquefied natural gas (LNG) to Europe to help EU allies in their efforts to fill gas storage ahead of the winter amid growing uncertainty about Russian gas supply. 

For the first time ever, the European Union imported in June more LNG from the United States than gas via pipeline from Russia, as Moscow slashed supply to Europe in the middle of last month.

Going forward, demand for U.S. LNG is set to remain robust as Europe races to reduce its dependence on Russian pipeline gas.  

In the U.S., LNG export capacity is growing as new trains at Sabine Pass and Calcasieu Pass came online this year. But in order to continue growing, the LNG industry will need more domestic midstream infrastructure – pipelines – to carry natural gas from production centers to LNG export terminals on the U.S. Gulf Coast and demand centers on the Eastern Seaboard. 

The Marcellus-Utica basin, the largest U.S. gas-producing region, and the second biggest gas-producing shale region, the Permian, could soon run into pipeline constraints that could undermine America’s ability to raise its LNG exports, energy analyst David Blackmon writes in Forbes.

The Federal Regulatory Energy Commission (FERC) hasn’t raced to approve pipeline projects, while the mixed messages from the Biden Administration continue to add uncertainties for upstream and midstream operators. 

There’s also opposition from communities to pipelines crossing their land or passing close to their homes. 

Such is the case with the Matterhorn Express Pipeline, designed to transport up to 2.5 billion cubic feet per day (Bcf/d) of natural gas through approximately 490 miles from Waha, Texas, to the Katy area near Houston, Texas.

The pipeline developers WhiteWater, EnLink Midstream, Devon Energy, and MPLX LP reached a final investment decision in May to move forward with the construction of the pipeline, expected to be in service in the third quarter of 2024, pending the receipt of customary regulatory and other approvals. 

But landowners in Williamson County, where the pipeline is planned to cross, are worried about the impact of the pipeline on their properties, although the county hosts at least a dozen pipelines already. Some Williamson County residents have asked the pipeline developers to reroute some parts of the project. 

“Williamson County lies in the most direct path from Midland to Freeport,” County Commissioner Russ Boles told Austin American-Statesman. 

The industry, for its part, calls for streamlined approval of pipeline projects that would help bring more gas to U.S. demand centers and LNG export facilities.

There are currently 11 major natural gas projects pending approval before the FERC, more than half of which have their final environmental documents, the Interstate Natural Gas Association of America (INGAA) said at the end of March 2022, days after the U.S. and the EU announced a deal for more U.S. LNG exports to the EU as the latter seeks to replace Russian supplies. 

“FERC’s approval is the imperative next step for these important projects. Without the additional capacity, which totals more than 12,141 MMcf/day pending currently, some of the added gas supply policymakers are calling on developers to produce will not reach American consumers or LNG terminals along U.S. coasts for export,” INGAA said. 

The American Petroleum Institute (API) has a ten-point plan to restore U.S. energy leadership. This plan includes a recommendation that the FERC “should cease efforts to overstep its permitting authority under the Natural Gas Act and should adhere to traditional considerations of public needs as well as focus on direct impacts arising from the construction and operation of natural gas projects.” 

U.S. LNG exports are set to decline in the second half of 2022 because of the outage at Freeport LNG, the EIA said in its latest Short-Term Energy Outlook (STEO) on Tuesday. U.S. LNG exports are forecast to average 10.5 Bcf/d in the second half of 2022, which is 14% less than the forecast in the June 2022 STEO. 

The EIA expects LNG exports will grow in 2023, averaging 12.7 Bcf/d on an annual basis, or 17% higher than in 2022.

The U.S. will need pipelines and a federal policy supporting such projects in order to continue growing LNG exports and delivering gas to the domestic demand centers.  

Oilprice.com by Tsvetana Paraskova, July 27, 2022

Chinese refineries’ throughput fell for the first time in more than a decade during the first half of the year, by 6 percent to 13.4 million bpd.

In June alone, processing rates were higher than in May, but some 10 percent lower than the all-time high reached last year in June, Reuters said in a report citing official data.

Oil imports also fell in June, according to data from energy analytics firm OilX—by 1.6 million bpd to 9.2 million bpd.

On an annual basis, OilX analysts noted, the June average was about 1 million bpd lower than what China imported in crude oil in June 2021. They noted, however, that despite the recent series of lockdowns because of Covid flare-ups, China’s oil imports were remarkably stable over the past few months.

Chinese oil production rose during the first half of the year, by 4 percent from a year ago, with the daily average at 4.15 million bpd. In June, domestic output hit an all-time high of 4.18 million bpd.

Refinery runs have suffered from Covid restrictions since the start of the year as Beijing maintained its zero-Covid policy and by fuel export restrictions the government has imposed on refiners.

The Covid restrictions have also dampened domestic demand for fuels, but analysts expect a pick-up in refinery runs in the current quarter as the government considers making amendments to its Covid policy and steps up infrastructure spending to boost economic growth. Gasoline and jet fuel demand were the worst affected by the Covid restrictions.

According to an earlier Reuters report, Beijing plans to set up a $75-billion infrastructure spending fund to stimulate growth. China booked GDP growth of 0.4 percent for the second quarter of the year, far below analyst expectations because of the worst outbreak of Covid since 2020 in the country.

Oilprice.com by Charles Kennedy, July 27, 2022

Russia turns off the Nord Steam 1 gas pipeline to Europe for its annual 10 days’ maintenance and no one is sure that it will be turned on again. If that’s it for gas deliveries this year, how many days of gas are currently in the storage tanks?

Europe is afraid that the Kremlin will spark a major energy crisis this winter by turning off its gas supplies completely. Gazprom reduced flows of gas to Europe by 60% in mid-June just as the tanks were half full.

The EU has set a target of having the tanks 80% full by the end of October and as bne IntelliNews reported, even at the reduced flow rates Europe should hit that target after the tanks reached 60% of capacity in the first week of July. Despite the reduction of gas from Russia, Europe is currently importing record amounts of LNG from the US that allow the gas in tank storage to continue growing.

But things are not quite that simple. Just getting to 80% full by the end of October is not enough gas to get through the whole heating season, which runs from October 1 to March 31, without continuous supplies of more gas during the winter.

Europe has large storage capacity, with the biggest facilities being in Germany and Ukraine. However, those facilities cannot hold enough to meet demand for the entire winter.

Storage levels and storage capacity vary greatly in the EU. The tanks in Poland and Portugal are already close to 100% full. However, even the full tanks in Poland and Portugal are not enough to get through the whole winter. They hold enough gas for 79 days of consumption and 24 days respectively. That means without new supplies during the winter they would run out of gas by January 18 and November 24 respectively if all gas supplies were cut off from the current levels of gas stored.

Indeed, this is the case for all the countries of Europe; most countries’ storage doesn’t hold enough gas to last the whole winter. The exceptions are the Slovak Republic and Austria, where their tanks do hold enough gas to get to the end of the heating season if full. Everyone else starts running out of gas as soon as October (assuming gas withdrawals start on October 1, but a mild winter means drawdowns can start as late as the start of November), although some survive until February. Czechia is in the third best position, as its tanks can last to April 5 if full.

But neither Poland nor Portugal will run out of gas even if Russia turns off the spigots. Poland will open a new pipeline to Norway on October 1 and is the first EU country to have entirely weaned itself off Russian gas supplies. Portugal’s supplies of gas are almost all LNG that is brought by ship under long-term contracts and also stands little chance of running out.

With the other countries much depends on their relations with Russia and the size of their tanks. Hungary’s storage tanks hold 133 days’ worth of gas, which means it would run out on March 13 if its tanks were full when Russia turned off supplies, but earlier this year it signed a new gas supply contract with Russia and has locked in supplies for this winter.

Germany remains the most exposed, as it is almost entirely dependent on Russian gas imports. Despite having by far the largest storage tanks in Europe, its demand for gas is equally large and its tanks only hold 108 days of consumption – full tanks would run dry on February 16 and they are currently only 60% full, which would be emptied on December 8 if Russia turned off the gas tomorrow.

The EU as a whole is in the same position with an average storage capacity of 98 days of consumption, so full tanks run dry on February 6, but as the tanks for the whole of the EU are also 60% full, if the gas were turned off tomorrow Europe would run out of gas on November 28 (assuming an October 1 start to winter).

And the country in the worst position is Ukraine, which also has huge storage tanks accounting for about 20% of Europe’s entire capacity, but those tanks are currently only 21% full. In the normal course of things Ukraine’s hold enough gas for 135 days of consumption, which takes it through to the middle of March, but the current amount of gas will run out on October 29 if deliveries are turned off tomorrow and at best the end of November if the autumn is mild.

Ukraine is very likely to have an energy crisis this winter, as it has not imported gas from Russia for over three years and its European friends will be short of gas for themselves this winter.

So even if Europe gets to its 80% full tank target by October 1, it remains at Russia’s mercy, as it will still need to import gas during the winter from somewhere to cover the missing months, albeit at lower volumes than now.

It is not clear how much LNG can make up the shortfall, but in general LNG supplies can cover some 15% of Europe depend and there are also technical limits on how much LNG Europe can import due to the capacity of available LNG terminals in Europe. There are other sources of gas from production in Norway and the Netherlands, but it is not enough for everyone.

Depending on how aggressive Russia is and to what extent it reduces flows, the scenarios Europe may face could be extreme. Europe needs to cut its usage by 15%, according to study by Bruegel, if it is to get through the winter. In the more extreme scenarios, it would have to ration gas and order companies to reduce industrial production to make sure there was enough gas to heat homes.

Germany has already introduced the “alert” status, the second of the EU’s energy crisis warning system, while another 12 EU member states are on the first “early warning” state. German Vice-Chancellor Robert Habeck, in charge of the economy and energy, has ordered coal-fired power stations to be readied in case Germany runs out of gas. Germany uses the bulk of its gas for heating and only 15% is used for power generation, which can be replaced by coal-fired power plants.

With a 15% reduction in consumption and by making use of non-Russian sources of gas, plus the alternative power sources like nuclear and coal, Europe should be able to survive the upcoming winter, the think-tanks said. But it won’t be fun.

bne INTELLINEWS by Ben Aris, July 14, 2022

Oslo has said the oil fund will only shed its stakes in oil and gas explorers and producers. It was widely expected that the world’s biggest sovereign fund would dump all of its oil and gas investments for good.

The Norwegian government said on Friday its $1 trillion asset manager— the world’s biggest sovereign fund — will sell its stake in oil and gas explorers and producers but will continue to invest in energy companies that have refineries and are engaged in distribution and retail sales of oil and gas products.

The announcement means the fund will remain invested in Big Oil companies such as Shell, BP, Total and ExxonMobil, in which it owns significant stakes.

Oslo said the move is based solely on financial considerations and that it does not reflect any particular view of the oil industry’s future prospects. Return on the fund’s investment in oil and gas stocks fell 9.5 percent last year.

Norway’s central bank, which manages the mammoth fund, has long maintained that the divestment was aimed at reducing the country’s exposure to the energy sector. The fund is used to invest the proceeds of the country’s oil and gas industry, amounting to more than 20 percent of Norway’s revenue.

“The Government is proposing to exclude companies classified as exploration and production companies within the energy sector from the Government Pension Fund Global,” the finance ministry said in a statement. “The objective is to reduce the vulnerability of our common wealth to a permanent oil price decline.”

It was widely expected that the fund would dump all of its oil and gas investments for good. Norges Bank, the central bank, had in 2017 proposed a total divestment of oil and gas stocks.

The fund had holdings worth around $37 billion — 5.9 percent of its total equity investments — in the oil sector at the end of last year. But a bulk of that amount is invested in integrated oil companies that are engaged in everything from exploration to selling fuel at the roadside.

‘Missed opportunity’

Norway’s decision evoked mixed feelings among climate activists, who were expecting Oslo to go the whole hog.

“It’s a lost opportunity,” Martin Norman of Greenpeace’s Norwegian chapter told DW. “We are running against time and Norway had a chance to move fast but instead decided to move slowly.”

Norman, however, said the Norwegian government’s announcement was a “step in the right direction” that would prompt other investors to back away from fossil fuels.

“The government has acknowledged the problem of over exposure to oil,” he said. “But I disagree with the medicine they are prescribing.”

By desi123.com, July 14, 2022

It’s not about the oil. This is what President Biden has said about its upcoming visit to the Middle East and, more specifically, Saudi Arabia. He even said, as reported by Politico, that he was not going to ask the Saudis for more oil. And yet it seems that few believe this. 

“No, I’m not going to ask them [to increase oil production],” the U.S. President said last week on his visit with the King and Crown Prince of Saudi Arabia.

“All the Gulf states are meeting. I’ve indicated to them that I thought they should be increasing oil production generically, not to the Saudi Arabia in particular. I hope we see them in their own interests concluding that makes sense to do,” he also said.

This is where Biden is quite wrong. It is not in the Gulf oil kingdoms’ interest to pump more. Most of them do not have any spare capacity, and the couple that do may have seriously overestimated that spare capacity. And this includes Saudi Arabia.

The issue of actual spare capacity came into the spotlight also last week when Reuters recorded France’s Emmanuel Macron telling Biden that the UAE was pumping near its maximum and Saudi Arabia could only add about 150,000 bpd to its production in short order.

“And then he [Sheikh Mohammed bin Zayed al-Nahyan] said (the) Saudis can increase by 150 [thousand barrels per day]. Maybe a little bit more, but they don’t have huge huge capacities before six months’ time,” the French President said, per the Reuters video footage.

According to estimates by the International Energy Agency, Saudi Arabia has a short-order capacity of 1.2 million barrels daily—the amount that can be added to current production in less than 90 days. The longer-term spare capacity, the IEA has estimated, stands at 2.1 million bpd. And the Kingdom’s sustainable production capacity is 12.2 million bpd, again per IEA estimates.

The problem with estimates is that they often tend to rely on insufficient information, including information supplied by the country with the spare capacity. But there is, in fact, no hard, verifiable data on Saudi Arabia’s or any other OPEC member’s spare production capacity. No OPEC member is obliged to report its spare capacity, and there is no way for the figures that they do report as spare capacity to be verified.

Per OPEC’s latest Monthly Oil Market Report, Saudi Arabia pumped 10.424 million bpd in June. That was 60,000 bpd higher than the average for May, and the Kingdom has pledged to boost production a lot more sharply this month and in August. But it might not be able to do it.

Reuters’ John Kemp noted in an analysis on the topic that Saudi Arabia has only ever reached a production level of 12 million bpd once, in April 2020. As for production sustained over a three-month period, the maximum demonstrated rate was 10.8 million bpd, pumped between October and December 2018, according to data from the Joint Organisations Data Initiative.

It gets even worse over a longer period. Per the data quoted by Kemp, Saudi Arabia’s maximum demonstrated output over a period of 12 months has been 10.5 million bpd.

So, on the one hand, Saudi Arabia is quite unlikely to have the resources needed to boost production in any meaningful way that would have an impact on international prices in the immediate term. But it also probably does not want to.

The thing about spare capacity in oil production is that it can be tapped in case of an emergency. But there is no oil emergency right now, not according to Riyadh. In fact, so far, Saudi Arabia, in the face of its energy minister and brother to the Crown Prince, Abdulaziz bin Salman, has claimed that the oil market is relatively balanced, but years of underinvestment in new production have now combined with sanctions to reduce supply.

The other thing about spare capacity in oil production is that once tapped, it stops being spare, if we are talking about more than a month or two. The less spare capacity, the less flexibility a producer would have when an actual emergency arises.

Saudi Aramco last year revealed plans to boost its production capacity to 13 million barrels daily. The expansion is scheduled to take until 2027, according to chief executive Amin Nasser. In other words, boosting the country’s maximum sustained oil production capacity by 1 million bpd will take eight years.

This does not mean there is nothing Saudi Arabia can do to boost production, according to Reuters’ Kemp. According to him, it could restart old wells that have been closed to “rest the fields” and maintain pressure, or they can drill new wells in producing fields.

Yet, while it could do these things, whatever its spare capacity actually is, the bigger question is whether Saudi Arabia would want to do these things. After all, it was just last month that Prince Abdulaziz said that the relations between Saudi Arabia and Russia were as warm as the weather in Riyadh.

Oilprice.com by Irina Slav, July 14, 2022

Exxon Mobil Corp.’s second-quarter refining earnings surged by as much as $5.5 billion, signaling a season of windfall profits for the fuel-making sector as consumers bear the burden of near-record gasoline prices.

Widening refining margins added as much as $4.6 billion during the quarter while the value of unsettled derivatives provided up to $900 million more, the Irving, Texas-based company said in a regulatory filing on Friday. Meanwhile, surging oil and natural gas prices boosted results by as much as $3.3 billion. 

Sky-high pump prices are intensifying broader inflationary trends and increasing pressure on political leaders to shield consumers through giveaways such as suspending fuel taxes. US President Joe Biden singled out Exxon’s profits for criticism last month, accusing the company of making “more money than God” at a time when consumers were suffering. 

Exxon’s bumper profits “are largely a result of underinvestment by many in the energy industry over the last several years,” spokesman Casey Norton said by email. The company invested in new supplies during the pandemic despite incurring a $22 billion loss in 2020, he noted.

Exxon has the largest refining footprint of the major oil companies at a time of soaring margins around the world due to high demand for gasoline and diesel and a shortage of facilities to make them. The world lost about 3 million barrels of daily refining capacity when the Covid-19 pandemic slashed consumption and fuel supplies have been further strained by Chinese export controls and sanctions on Russia.

High product prices and refining margins are “set to stay high for some time,” and at least through the first half of next year, Alastair Syme, an analyst at Citigroup Inc. write in a note.

Exxon invested almost $120 billion in capital projects between 2017 and 2021, more than double what it earned, Norton said. “We did this to meet society’s energy demands and, in fact, are investing more than any other US company to grow oil and natural gas production.”

RIGZONE by Kevin Crowley, July 8, 2022