PFD Politics. Betting Big on $100 Oil. Climate Activists Unlikely Cheerleaders.

In News by wp_sysadmin


PFD and the special session; the clock ticks down toward June 19
Tim Bradner, The Frontiersman, June 8, 2021

The special legislative session that began May 20 in Juneau continues, defying predictions by many that all would be done before Memorial Day.

Gov. Mike Dunlevy called lawmakers into special session as the regular session ended May 19 with the state budget unfinished and a Permanent Fund Dividend for 2021 undecided.

Since then a budget conference committee has continued work to reconcile versions of the budget passed by the state House and State Senate. Differences between the two are relatively minor, except for the PFD.

Discussions on that are underway, mostly behind closed doors.

Basically, the disagreement is on how much the dividend will be and how it can be paid. Talks are ranging between a modest dividend, such as $750 or $1,000 supported by some legislators, or a larger PFD of over $2,000 based on a new formula proposed by Gov. Mike Dunleavy. The new formula, called the “50-50” plan, would split the annual payment the Permanent Fund makes to the state to support the budget.

Estimates by the Legislative Finance Division are that a modest dividend of $750 to $1,000 can be paid from existing revenues and cash in the Constitutional Budget Reserve, a state savings account. There would not be a need to take more money from Permanent Fund earnings.

The larger PFD, however, would require a larger withdrawal from Permanent Fund earnings. The governor has said that he’s open to this as a one-time “overdraw,” assuming that it would be followed by legislators’ approval of a constitutional amendment putting the dividend into the Constitution, thus guaranteeing it, along with the “50-50” split of funds from the Permanent Fund.

However, there is no guarantee the Legislature, or Alaska voters, will approve the amendment, and the short-term plan for an overdraw to fund this year’s dividend is meeting opposition in the Legislature, where many lawmakers feel it just demonstrates that whenever the Legislature needs more money it is just drawn more from the Fund’s earnings.

Meanwhile, the slow pace of the budget and PFD negotiations is a growing concern. If things will drag on in Juneau until June 19, the end of the 30- day special session, the session will end with 11 days left before June 30, the end of the state fiscal year. If there is no budget passed and signed by the governor on July 1, the start of Fiscal Year 2022, the state cannot legally operate. State employees, contractors and vendors cannot be paid.

That would be very disruptive, although it has come close to happening before. There are short-term “workarounds” for an even like this including short-term borrowing to fund essential state operations like troopers and prison guards, but this might be the case only if the operating budget is agreed on and it is just a matter of days in getting the governor’s signature.

But if it’s a political impasse with no clear near-term solution, those options may not be available. All indications are, however, that an operating budget will be passed by June 19 to avoid disruptions. The divisive PFD decision might be deferred, for example by inserting it into another appropriation bill that could be debated in a second special session called by Dunleavy later in the summer.

If the PFD can’t be decided by June 19 the governor may not want to wait until late summer, however. He could call another special session immediately to keep lawmakers in Juneau another 30 days to work on the dividend.


Options Traders Bet on Return of $100 Oil
Joe Wallace, The Wall Street Journal, June 7, 2021

Traders have alighted on what some believe to be a one-way bet in the world’s most important commodity market: oil prices going to $100 a barrel.

They have scooped up call options tied to Brent and West Texas Intermediate crude-oil prices reaching $100 by the end of next year. Oil prices haven’t topped that milestone since 2014, when a gush of U.S. crude depressed energy markets.

Owners of $100 options—now the most widely owned WTI call contracts on the New York Mercantile Exchange—are making a leveraged bet that oil prices will hurtle higher after already surging more than 40% this year. The roaring rally, goosed by thawing coronavirus restrictions, has lifted WTI prices to their highest level since 2018 at almost $70 a barrel and average U.S. gasoline prices above $3 a gallon, according to GasBuddy.

The popularity of $100 options is another example of traders converging on seemingly outlandish wagers they consider to be almost guaranteed ways of making money. Analysts say oil is unlikely to zip to $100 any time soon because the world economy is still recovering from the shock of Covid-19 and major producers are lifting output in response to resurgent demand.

“Everyone’s been looking at it,” Adam Webb, chief investment officer of trading firm Blue Creek Capital Management LLC, said of $100 call options for oil delivered in December 2022. “It’s a no-brainer.”

Mr. Webb thinks the rebound in the U.S. economy will help to catapult WTI prices toward $100 a barrel. The fund has sold put options to fund the purchase of $100 calls, which he judges to be unsustainably cheap.

The flurry of activity in $100-oil options holds parallels with speculative wagers that have proliferated in other corners of financial markets. In January, traders piled into options on unprofitable companies such as GameStop Corp. and AMC Entertainment Holdings Inc. They figured doing so would boost share prices, inflict losses on bearish investors and prompt them to buy back shares they had sold short. The self-fueling dynamic drove prices even higher in a trading frenzy that reignited in early June.

Betting on an imminent return to $100 for oil is striking just over a year after the pandemic slammed energy demand and U.S. crude futures tumbled below zero. Products derived from crude fuel cars, power electricity generators and are the building blocks of plastics, making oil a vital component of the world economy. Spikes in crude markets are to some extent self-correcting because higher prices curtail demand and encourage greater production.

Barring an influx of investors into commodity markets or a slump in the dollar, oil demand would need to rise well above pre-pandemic levels in the fourth quarter for prices to hit $100 this year, according to JPMorgan Chase analyst Natasha Kaneva. She says that is all but impossible. Other grounds for caution include an increase in Iranian crude exports in the event of a nuclear deal with the U.S.

That hasn’t deterred traders from building a big position in $100 call options. The contracts give their owner the right to buy crude futures at $100 a barrel. They pay out if prices rise above that strike price before expiration.

December 2022 contracts with a strike of $100 are by far the most widely owned WTI call option on the New York Mercantile Exchange. There are more than 60,000 outstanding, according to options-data provider QuikStrike, covering more than 60 million barrels of crude.

Some traders are betting $100 oil could happen this year: $100 December 2021 calls are tied to 15.9 million barrels of WTI. In London’s Brent market, $100 contracts for December 2021 covered more than 32 million barrels last week, up from none at the end of last year, according to Intercontinental Exchange.

Even some of those buying the options don’t expect oil prices to hit $100 but think they will profit regardless. Traders say the contracts, dubbed lottery tickets, will likely appreciate if oil prices keep rising or if participants expect crude markets to grow more volatile.

Buyers are betting on higher volatility more than they are placing a wager on higher oil prices, said Robert Yawger, director of energy futures at Mizuho Securities USA. Volatility and options are intrinsically linked, so all else being equal, that would boost the price of the contracts.

Mr. Yawger doesn’t think oil will get close to $100 a barrel, noting that the futures market pegs WTI prices at about $61 a barrel for December 2022. He said owners of $100 calls will benefit anyway because expected volatility is low and likely to rise. Sellers are “basically giving [volatility] away” at current prices, he said.

A trader who bought $100 calls for December 2022 at the end of last year would already be sitting on paper gains. The contracts traded at 70 U.S. cents Monday, QuikStrike data show, up from 27 cents on Dec. 31.

Traders say they are still relatively cheap because demand from producers seeking protection against falling prices means oil puts are typically more expensive than calls. The $100 call trade isn’t risk free, however.

Jean-Louis Le Mee, chief executive of Westbeck Capital Management LLP, forecasts crude prices will surge to record highs in 2023 but is surprised at how many $100 Brent call options for 2021 are outstanding. The hedge fund steers clear of such bullish contracts, preferring to buy options that Mr. Le Mee thinks will settle in the money. Even if volatility rises, $100 contracts will lose value if it happens too close to expiration, he said.

Instead, Westbeck has booked profits by selling $65 Brent-crude calls for December 2022 that it bought last year and used the proceeds to buy $80 contracts for December 2023.


The World’s Liquefied Natural Gas Market Is Roaring Back
Hellenic Shipping News, June 6, 2021

Accounting for ~15% of global gas consumption, the 48 Bcf/d global liquefied natural gas (LNG) is on the move again.

After an obviously rough 2020, where Covid-19 caused just 1% demand growth, all-important Asian prices have been around $10 per MMBtu for summer, versus below $2.00 for last summer.

This could be the highest summer LNG prices since 2014.

Asia and Europe are both replenishing gas inventories after a harsh winter and colder April to ready for winter 2021-2022.

China’s May LNG imports, for instance, just set a record for the month, up 26% year-over-year.

This is great news for the U.S. LNG business, ranked as the third largest supplier.

U.S. gas has wide arbitrage opportunities since domestic prices are $3.00, even much lower for futures prices starting in Q2 2022.

Last year, it was a sunken export market that kept domestic U.S. gas prices at a crazy low $1.60 for June.

Beating Covid-19, U.S. gas demand last May-September was about the same as the records set for the same period in 2019, at ~75 Bcf/d.

For April, the U.S. Department of Energy (DOE) reports that our LNG exports averaged 9.2 Bcf/d, after setting a record in March at 10.5 Bcf/d.

Up from 6.5 Bcf/d in 2020, DOE has our exports at 9.0 Bcf/d this summer and averaging 9.2 Bcf/d for 2022.

Asia is the obvious price because it holds 75% of global LNG demand and is expected to account for a staggering 95% of new demand from 2020-2022.

LNG Over the Long-Term

For natural gas as a commodity, global use will stay resilient even in a policy scenario where the human-induced rise in global temperatures is held to 2 degrees C or less.

This explains why net-zero carbon gas companies like BP and Shell are expanding their LNG portfolios, not to mention giant commodity traders like Vitol touting gas as a “cost effective and cleaner fuel solution.”

The reality is that progress towards a clean energy future must include investments in gas infrastructure: some 85% of all humans live in still developing countries, desperate for the very same energy that made us Westerners rich.

The notion that the still developing countries will somehow drastically curtail their energy options (i.e., block fossil fuel usage) is being overplayed by the developed countries.

Setting the example for others, gas now generates 40% of U.S. electricity, double second place coal and nuclear – a “dash to gas” that has significantly cut the country’s CO2 emissions.

In turn, the recent International Energy Agency’s advice – which contradicted its previous investment advice over the past decades – of no more upstream coal, gas, or oil projects is only being heard by its 38 member OECD countries.

These are the rich nations that comprise just 15% of the world’s population.

Simply put, Russia, China, and OPEC nations are ready to be gifted from such a recommendation, already helped by last week’s “climate activist wins” against Chevron, Shell, and Exxon.

Take OPEC’s Nigeria alone, where oil alone accounts for half of government revenues, which is ready to “Kick-start 100 Oil & Gas Projects Between 2021 and 2025.”

And be careful tossing climate shame at the Nigerian government for an obsession with economic development: 80 million Nigerians live on less than $1 a day.

As rich California painfully found out last summer, gas is the key backup fuel for wind and solar energy development because they are naturally intermittent, typically available only 25-40% of the time.

More long-term contract signings are reinstalling optimism for LNG developers.

The export industry is looking beyond the traditional Asian demand centers, like Japan, South Korea, and most recently the boom of China.

Along with currently Covid-19 devastated India, emerging markets such as Myanmar, Vietnam, and the Philippines are becoming vital for LNG sellers.

Demand in Southeast Asia could quintuple over the next decade.

With only one LNG project taken a final investment decision in 2020 (Sempra Energy’s project along Mexico’s west coast), new ones getting greenlighted will help facilitate growth in LNG consumption.

Fully developed Europe will remain integral as a swing demand center but incremental needs are limited.

The Middle East and Brazil will see moderate growth in LNG consumption.

Global LNG demand is slated to rise 40-50% over the next 10 years and perhaps even double to nearly 100 Bcf/d by the early-2040s.

There are currently around 16-18 Bcf/d of projects under construction, but an additional 8-10 Bcf/d of new projects will be needed over the next decade alone.

Longtime key suppliers such as Malaysia, Indonesia, Trinidad and Tobago, and the UAE are facing a declining ability to export.

The top five producers by 2030 will be Qatar, the U.S., Australia, Russia, and perhaps Mozambique and could total over 75% of LNG sales.

U.S. projects will need to be highly competitive to compete.

Developers here are also looking to enhance their ESG positioning with carbon capture and sequestration facilities at LNG plants, a key to reach Europe where U.S. LNG has already been denied because of methane emissions.

For example, EQT, the largest U.S. gas producer, has called to reverse the rollbacks of methane regulations.

Qatar’s $30 billion, 40% LNG capacity expansion project for its immense North Field (appraised at a mind-blowing 1,760 trillion cubic feet) is a game-changer and will equal 20% of global export capacity.

Qatar has the lowest production costs in the world and is looking to China for investments, a shift from Qatar’s normal partnering with the western majors for technology and global outreach.

Qatar is even working with ExxonMobil for the Golden Pass LNG export project in Texas.

Mighty Russia also wants to extend beyond its pipeline dominance to controlling 25% of the global LNG market over the next 15 years.

One more interesting question will be if Canada can eventually ship LNG from its western coast to Asia, having an advantage over U.S. suppliers in the Gulf that are more distant and must pass through the Panama Canal’s hefty tolls and traffic.

With huge offshore gas deposits but also facing violence and civil unrest, Mozambique is also LNG competition for the U.S.

But those of us demanding a much larger focus on alleviating horrific energy poverty (to me, the west has made it the world’s forgotten calamity) around the world have serious questions about Mozambique.

Only about 40% have Mozambique’s population has access to electricity, meaning that over 19 million people – about the population of metro New York City – in the much-hyped emerging LNG exporting nation have no access to electricity.

Yet, Mozambique is somehow primed to ship away huge amounts of natural gas, the world’s go-to fuel.

This has become a typical problem: 70-75% of the huge energy resources in sub-Saharan Africa, where some 600 million people have no access to electricity, has been bound for export to richer and mostly energy-fulfilled nations.

For an oil and gas industry critically looking to enhance its ESG positioning and public relations image, the Mozambique LNG export push must not become another black eye.

I reported on this very opportunity sometime back that “Oil And Natural Gas Companies Could Be Heroes In Africa.”

Even more, China is increasingly investing in sub-Saharan Africa for its plethora of minerals and critical materials required globally for “the green energy transition,” centered on hundreds of millions, if not billions, of wind and solar power farms and electric cars.

China’s Belt and Road cooperation to access natural resources around the world quietly just got its 45th partner: the DR Congo that mines over 70% of the world’s cobalt.

We do know that in our climate-energy discussion, distant promises come extremely cheap: “China burned over half the world’s coal last year, despite Xi Jinping’s net-zero pledge.


Biden administration sets up ‘strike force’ to go after China on trade
Reuters, June 8, 2021

The United States will target China with a new “strike force” to combat unfair trade practices, the Biden administration said on Tuesday, as it rolled out findings of a review of US access to critical products, from semiconductors to electric-vehicle batteries.

The “supply chain trade strike force,” led by the U.S. trade representative, will look for specific violations that have contributed to a “hollowing out” of supply chains that could be addressed with trade remedies, including toward China, senior administration officials told reporters.

Officials also said the Department of Commerce was considering initiating a Section 232 investigation into the national security impact of neodymium magnet imports used in motors and other industrial applications, which the United States largely sources from China.

President Joe Biden ordered the review of critical supply chains in February, requiring executive agencies to report back within 100 days on risks to U.S. access to critical goods like those used in pharmaceuticals as well as rare earth minerals, for which the United States is dependent on overseas sources.

Though not explicitly directed at China, the review is part of a broader Biden administration strategy to shore up U.S. competitiveness in the face of economic challenges posed by the world’s second largest economy.

“Semiconductors are the building blocks that underpin so much of our economy, and are essential to our national security, our economic competitiveness, and our daily lives,” U.S. Commerce Secretary Gina Raimondo said in a statement. Other top U.S. economic officials are scheduled to address reporters at the White House at 1 p.m. (1700 GMT).

The United States faced serious challenges getting medical equipment during the COVID-19 epidemic and now faces severe bottlenecks in a number of areas, including computer chips, stalling production of goods such as cars.

U.S. agencies are required to issue more complete reports a year after Biden’s order, identifying gaps in domestic manufacturing capabilities and policies to address them.

Trade wars with allies not wanted

A senior official said the United States had faced unfair trade practices from “a number of foreign governments” across all four of the supply chains covered in the initial review, including government subsidies, and forced intellectual property transfers.

“Obviously, a number of Chinese industrial policies have contributed to vulnerable U.S. supply chains,” the official said. “I think you are going to see this strike force focusing in feeding into some of our China policy developments.”

The United States was not looking to “wage trade wars with our allies and partners,” the official added, noting the strike force would be focused on “very targeted products.”

But the senior officials offered little in the way of new measures to immediately ease chip supply shortages, noting in a fact sheet that the Commerce Department would work to “facilitate information flow” between chip makers and end users and increase transparency, a step Reuters previously reported.

In medicine, the administration will use the Defense Production Act to accelerate efforts to manufacture 50 to 100 critical drugs domestically rather than relying on imports.

And to address supply bottlenecks from lumber to steel that have raised fears of inflation, the administration is starting a task force focused on “homebuilding and construction, semiconductors, transportation, and agriculture and food.”

Semiconductors are a central focus in sprawling legislation currently before Congress, which would pump billions of dollars into creating domestic production capacity for the chips used in everything from consumer electronics to military equipment.

Biden has said China will not surpass the United States as a global leader on his watch, and confronting Beijing is one of the few bipartisan issues in an otherwise deeply divided Congress.

But some lawmakers have expressed concerns that a package of China-related bills includes huge taxpayer-funded outlays for companies without safeguards to prevent them from sending related production or research to China.

The official said a measure of success of the supply chain effort would be more diverse suppliers for crucial products from like-minded allies and partners, and fewer from geopolitical competitors.

“We’re not going to build everything here at home. But we do have to see more domestic manufacturing capability for key products,” the official said.


Biden clean energy plan faces permitting ‘choke point’
Jeffrey Tomich, E&E News, June 8, 2021

President Biden’s goal to create a carbon-free power sector by 2035 is seen as a sprint because of the pace required to deploy vast amounts of wind and solar energy and battery storage to displace fossil fuels.

A better analogy might be an obstacle course. Even if Congress passed a clean electricity standard, barriers would remain. Interconnection queues to the grid are backlogged. Billions of dollars of transmission will be required to connect new wind and solar farms to cities.

Perhaps the most difficult challenge? According to former President Trump’s infrastructure czar, it’s the many regulatory approvals needed to site and build projects.

“It is absolutely a choke point,” said D.J. Gribbin, who served in the White House during the Trump administration as the nation’s first special assistant to the president for infrastructure. “The constraint is not capital. The constraint is the ability to actually build new facilities.”

From federal and state environmental permitting requirements to local siting decisions, it can take years to get necessary approvals to bring a wind, solar or transmission project online.

Gribbin, who left the White House in 2018 and founded strategic consulting firm Madrus LLC, recently wrote about the permitting challenge in a blog post for the Brookings Institution, where he’s a nonresident senior fellow.

He cited a 2020 Council on Environmental Quality report showing that across federal agencies, the average completion time for an environmental impact statement required for many proposals under the National Environmental Policy Act was 4 ½ years. In some cases, approvals can require more than a decade.

At the local level, energy projects often need zoning approval — a process that carries significant political risk for developers as pushback from opponents has scuttled wind and solar projects.

Gribbin said utilities have historically built new power plants and transmission at a much slower pace than would be required under Biden’s 2035 plan, so permitting constraints haven’t been the barrier they will be as both the number and scale of projects must increase to meet Biden’s goal.

A Princeton University study earlier this year said wind and solar capacity would need to grow fourfold to 600 gigawatts for the U.S. to achieve net-zero carbon emissions economywide by midcentury. Most of the growth would be onshore, requiring some 228,000 square miles, or the equivalent of Illinois, Indiana, Ohio, Kentucky, Tennessee, Massachusetts, Connecticut, and Rhode Island combined (Energywire, March 24).

Midwestern states including Iowa, Missouri, Illinois, and Indiana would see 20% to 30% of their land devoted to renewable energy.

“Just to utilize that much land for energy generation is going to create a whole series of issues,” Gribbin said.

The White House did not respond to a request for comment.

‘Think about things more rationally’

Those challenges are already evident. More than 100 cities, counties and states around the country have enacted ordinances and laws restricting renewable energy projects, according to a recent report from Columbia Law School’s Sabin Center for Climate Change Law. Collectively, the restrictions threaten to slow the pace of the energy transition.

States seeking to encourage renewable development to help meet climate goals have sought to intervene.

New York passed a law last year creating an Office of Renewable Energy Siting — the first state agency dedicated solely to siting renewable projects, for example. The law to streamline renewable siting is aimed at overhauling a process seen as an obstacle to achieving the state’s climate goals.

The state of Michigan last year rolled out the nation’s first searchable database of local ordinances for siting renewable energy projects, with the goal of helping both municipalities and developers looking to site renewable energy projects.

Solar and wind projects in Michigan are often permitted by more than 1,800 different townships or cities, said Sarah Mills, a senior project manager at the University of Michigan’s Graham Sustainability Institute, who helped coordinate the database.

Mills is part of a team of academic researchers working under a Department of Energy grant that’s now looking across six Great Lakes states to find which localities have proactively zoned for solar and study the impacts of utility-scale solar projects on rural communities.

Mills has urged counties to be prepared when renewable energy developers come knocking. Doing so can provide certainty for developers, which face less risk that a township or county will reject a project. It’s also good for communities to determine how projects should be sited before they’re faced with a decision.

“It makes it better that you’ve already had the decision about how you’re going to treat projects, even if you need to hear people’s concerns about a particular project,” she said. “You can think about things more rationally when there’s not money on the table.”

The increasing pace and scale of renewable projects — particularly solar — is also causing new tension over the role of states.

In states like Indiana and Illinois, where counties have siting jurisdiction, bills were proposed this year to create uniformity for siting standards. In Indiana, H.B. 1381 would have created “no stricter than” siting requirements. But the bill failed amid strong opposition by Indiana counties that viewed the measure as an encroachment on their power to self-govern.

In Illinois, Democratic Gov. J.B. Pritzker included a similar proposal for “backstop” siting standards as part of a sweeping energy and climate proposal last month.

Meanwhile, in Ohio, where renewable energy projects are permitted by a state agency, Republican legislators are again pushing for a bill that would give residents in a township the power to veto a wind or solar project via referendum.

While the federal government has little to say about local permitting decisions, Gribbin said the Biden administration can take steps to help speed up the energy transition by streamlining the federal permitting process.

“What kind of puts a pin in this issue is the fact that we’re trying to convert 80% of our generation to something different in the next 15 years. That is really aggressive, and therefore we need to think completely differently about how we permit projects.”


OPEC, Russia seen gaining from climate activist wins
Dmitry Zhdannikov, Reuters, June 1, 2021

Climate activists who scored big wins against Western majors last week had some unlikely cheerleaders in the oil capitals of Saudi Arabia, Abu Dhabi and Russia.

Defeats in the courtroom and boardroom mean Royal Dutch Shell (RDSa.L), ExxonMobil (XOM.N) and Chevron (CVX.N) are all under pressure to cut carbon emissions faster. That’s good news for the likes of Saudi Arabia’s national oil company Saudi Aramco (2222.SE), Abu Dhabi National Oil Co, and Russia’s Gazprom (GAZP.MM) and Rosneft (ROSN.MM).

It means more business for them and the Saudi-led Organization of the Petroleum Exporting Countries (OPEC).

“Oil and gas demand is far from peaking and supplies will be needed, but international oil companies will not be allowed to invest in this environment, meaning national oil companies have to step in,” said Amrita Sen from consultancy Energy Aspects.

Climate activists scored a major victory with a Dutch court ruling requiring Shell to drastically cut emissions, which in effect means cutting oil and gas output. The company will appeal.

The same day, the top two U.S. oil companies, Exxon Mobil and Chevron, both lost battles with shareholders who accused them of dragging their feet on climate change.

The International Energy Agency, which looks after the energy policies of the West, issued an appeal last month to the world to essentially scrap all new oil and gas developments. But it gave no clear formula on how to reduce demand.

“It (the IEA report) is a sequel of the La La Land movie. Why should I take it seriously?” Saudi Energy Minister Prince Abdulaziz bin Salman said on Tuesday.

“We (Saudi Arabia) are … producing oil and gas at low cost and producing renewables. I urge the world to accept this as a reality: that we’re going to be winners of all of these activities,” he told an online news conference after a regular OPEC+ meeting.


A high-level executive from Russia’s Gazprom said: “It looks like the West will have to rely more on what it calls ‘hostile regimes’ for its supply”.

Saudi Aramco, Adnoc and Gazprom all declined to comment. Oil major Rosneft, in which the Russian state has the biggest stake, also declined to comment.

Western oil majors like Shell have dramatically expanded in the last 50 years, as the West sought to cut its reliance on energy from the volatile Middle East and from Russia.

Those same Western energy majors, including BP (BP.L) and Total (TOTF.PA), have set out plans to sharply reduce emissions by 2050. But they face growing pressure from investors to do more to meet U.N.-backed targets to limit global warming.

Saudi Aramco, listed on the Saudi bourse but majority state owned, is not under the same sort of pressure to cut its carbon emissions, although the kingdom’s rulers aim to sharply increase the country’s use of renewables.

Gazprom expects demand for natural gas to grow in coming decades and for it to play a bigger role in energy consumption than renewable sources and hydrogen.

Western oil majors control around 15% of global output, while OPEC and Russia have a share of around 40 percent. That share has been relatively stable in recent decades as rising demand was met with new producers like smaller private U.S. shale firms, which face similar climate-related pressures.


Since 1990, global oil consumption has grown to 100 million barrels per day from 65 million bpd, with Asia providing the lion’s share of growth.

Countries such as China and India have made no pledges to reduce oil consumption, which on a per-capita basis is still a fraction of the levels in the West. China will rely heavily on gas to cut its huge coal consumption.

Despite pressure from activists, investors, and banks to cut emissions, Western oil majors are also tasked with maintaining high dividends amid heavy debts. Dividends from oil companies represent significant contributions to pension funds.

“It is vital that the global oil industry aligns its production to the Paris goals,” said Nick Stansbury at Legal & General, which manage £1.3 trillion ($1.8 trillion) in assets on behalf of savers, retirees, and institutions. “But that must be done in step with policy, changes to the demand side, and the rebuilding of the world’s energy system.

“Forcing one company to do so in the courts may (if it is effective at all) only result in higher prices and foregone profits,” Stansbury said. Legal & General, one of the world’s largest fund managers, holds assets in most oil majors.

Climate lawsuits have been filed in 52 countries in the past two decades, with 90% of those in the United States and European Union, risk consultancy Verisk Maplecroft said.

“The same oil and gas will still be produced. Just with lower ESG standards,” said an executive from a Middle Eastern producer, who previously worked for an oil major, referring to environmental, social and governance performance measurements.