Ultimate Resource Covering US Oil, Gas And Shale Industry (#GotBitcoin)

Smaller drillers, which account for sizable part of U.S. oil production, are struggling to pay off hefty debt burdens. Ultimate Resource Covering US Oil, Gas And Shale Industry (#GotBitcoin)

Bankruptcies are rising in the U.S. oil patch as Wall Street’s disaffection with shale companies reverberates through the industry.

Twenty-six U.S. oil-and-gas producers including Sanchez Energy Corp. and Halcón Resources Corp. have filed for bankruptcy this year, according to an August report by the law firm Haynes & Boone LLP. That nearly matches the 28 producer bankruptcies in all of 2018, and the number is expected to rise as companies face mounting debt maturities.

Energy companies with junk-rated bonds were defaulting at a rate of 5.7% as of August, according to Fitch Ratings, the highest level since 2017. The metric is considered a key indicator of the industry’s financial stress.

The pressures are due to companies struggling to service debt and secure new funding, as investors question the shale business model.

Many drillers financed production growth by becoming deeply indebted, betting that higher oil prices would sustain them. But investor interest has faded after years of meager returns, and some companies are struggling to meet their obligations as oil prices hover below $60 a barrel.

Private companies and smaller public drillers have been hit hardest so far. Those producers collectively generate a large portion of U.S. oil, according to consulting firm RS Energy Group, and their distress reflects issues affecting all U.S. shale.

“They were able to hang in there for a while, but now their debt levels are just too high and they’re going to have to take their medicine,” said Patrick Hughes, a partner at Haynes & Boone.

Halcón Resources filed for bankruptcy protection in August, three years after its last trip through bankruptcy court, as it contended with a production slowdown in West Texas and higher-than-expected gas-processing costs.

Halcón’s chief restructuring officer, Albert Conly of FTI Consulting Inc., said in a court filing that those challenges led the company to become more highly leveraged, which violated the loan covenant on its reserve-backed loan. That prompted lenders to cut Halcón’s credit line by $50 million earlier this year, Mr. Conly said.

Sanchez Energy filed for bankruptcy protection Aug. 11, citing falling energy prices and a dispute with Blackstone Group Inc. over assets they had jointly acquired from Anadarko Petroleum Corp. in Texas’ Eagle Ford drilling region in 2017. Blackstone claimed Sanchez defaulted on a joint deal to develop the assets, and that it was entitled to take them over, which Sanchez disputed.

Other shale drillers have recently missed key debt payments, and could be forced into bankruptcy.

EP Energy Corp. missed a $40 million interest payment due Aug. 15 as it struggled under the weight of debt it took on to help private-equity investors including Apollo Global Management LLC buy the company in 2012.

As of the second quarter, the Houston-based driller’s total debt was six times its earnings, excluding interest, taxes and other accounting items, according to S&P Global Market Intelligence, well above the level at which lenders generally consider loans to be troubled.

The company has said in securities filings that it has until mid-September to make its interest payment, and it is considering a range of options that include filing for bankruptcy protection.

Unlike several years ago, the current round of bankruptcies isn’t driven by a collapse in crude prices. The U.S. benchmark oil price has roughly doubled since 2016, when crude bottomed out below $30 a barrel. That year, 70 U.S. and Canadian oil-and-gas companies filed for bankruptcy, according to Haynes & Boone.

The current financial strain on shale producers is likely to intensify as many companies that took on debt after the 2016 oil slump face large debt maturities in the next four years. As of July, about $9 billion was set to mature throughout the remainder of 2019, but about $137 billion will be due between 2020 and 2022, according to S&P.

The debt of Houston-based Alta Mesa Resources Inc. is among the riskiest U.S. bonds, according to Fitch. Initially handed a $1 billion blank check by investors to invest in shale, the company said earlier this year its future is in question.

“A lot of companies are highly levered and facing maturities on their debt that I like to call a murderer’s row, maturities are coming year after year,” said Paul Harvey, credit analyst at S&P.

That could spur a race to refinance, but many energy bonds are pricing higher. A metric that measures the lowest possible yield an investor can earn on a bond without the issuer defaulting was more than 7% in July for oil and gas bonds, compared to about 4% for the overall corporate market, according to S&P. For oil and gas bonds considered junk, such yields were nearly 13%.

Energy is the largest sector of the high-yield market, but companies have backed away as the cost of capital has increased. As of July, this year’s energy high-yield issuances had fallen 40% from the same period a year earlier, while overall corporate high-yield issuances rose 32%, according to Fitch Ratings.

“Any available capital structure is going to be more expensive than it was a year ago,” said Tim Polvado, the head of U.S. energy for the Paris-based bank Natixis SA.

As is often the case in corporate bankruptcies, many equity holders might be all but wiped out while bondholders emerge as the owners of reorganized shale companies.

Senior bondholders in Houston-based Vanguard Natural Resources LLC traded about $433 million in debt for nearly all of the equity of the reorganized company, now named Grizzly Energy LLC, after the firm filed for bankruptcy earlier this year. The company’s Class C shares trade for a penny each.

Updated: 12-2-2019

Brent Oil Set To Disappear As Crude-Price Benchmark Lives On

Royal Dutch Shell is set to plug its last remaining Brent oil wells in the North Sea next year.

The world’s most famous oil and gas field—and the backbone of global crude pricing—has dried up. Soon the Brent benchmark will have no Brent oil.

Royal Dutch Shell PLC is expected next year to plug the last remaining Brent oil wells, located in the North Sea’s East Shetland Basin, about 115 miles northeast of Scotland’s Shetland Islands. The closures mark the end of an era, as the industry shifts its focus to smaller oil finds near existing infrastructure.

Many companies are shutting down platforms above massive fields discovered in the 1970s, but Brent stands apart as one of the first and most significant of these finds. The field has generated billions of dollars for Shell, its partner in the field, Exxon Mobil Corp. and the U.K. government.

In the late 1980s, Brent crude became the benchmark on which most of the world’s oil is priced and is still used to set the price of the multi-trillion dollar Intercontinental Exchange Brent futures market.

“The role it has played is a cornerstone for this industry now for 40 plus years,” said Steve Phimister, vice president of upstream and director of U.K. operations at Shell.

The Brent benchmark will keep its name and increasingly represents a blend of North Sea crudes, with the potential to include oil from other locations in the future.

Shell discovered the field in 1971 and named it after the brent goose, keeping with the seabird theme the company used for naming its discoveries at the time. Developing it was a huge and expensive undertaking. Standing as tall as the Eiffel tower, Brent Charlie, the last active platform of Brent’s original four, was built to withstand some of the most hostile conditions on earth.

The North Sea’s wave heights of up to 12 meters and gale-force winds of up to 100 miles an hour make it a place for “hardy individuals,” said Aberdeen-based Alan Lawrie, who joined Shell in 1984 when he was 16 years old. Now 51 and manager of Shell’s Charlie platform, he said Brent was the field everyone vied to work on.

Like all of the approximately 180 workers on the platform, Mr. Lawrie is on a fly-in fly-out rotation, spending two weeks offshore at a time and working 12-hour shifts while there. The Charlie platform can house up to 192 people in what is like a miniature village on an island in the middle of nowhere. It has restaurants, games rooms and a gym—where Mr. Lawrie has spent much of his downtime on a rowing machine.

One of his fondest memories is celebrating his 21st birthday on Charlie with his colleagues, who teased him with a gift of an 18-inch model wooden oar that one of them had whittled between shifts on the platform.

The North Sea oil rush was helped by higher oil prices after the Arab Oil Embargo in the early 1970s, when crude prices quadrupled. Oil got another jolt from shortages caused by the Iranian Revolution in 1979.

“We were importing all our oil and the main emphasis from the U.K. government, and oil companies was to get to first oil as quickly as possible, to help our balance of payments, which was suffering badly because of a huge bill for paying for oil imports,” says Alex Kemp, professor of petroleum economics at the University of Aberdeen Business School.

The project was risky and had massive cost overruns, as the North Sea was a frontier region, and the effort used new technologies to go deeper underwater than ever before and drill more than 4 miles beneath the seabed.

North Sea oil production has been in decline since the turn of the century, partly because it was too expensive to compete with other regions. At its peak in 1982 Brent produced more than 500,000 barrels a day, enough to meet the annual energy needs of around half of all U.K. homes at the time. The U.K. region of the North Sea produced around 1.8 million barrels a day of oil and gas last year, less than half the peak hit in 1999.

As Brent production declined, several other oil grades were added to what is now a basket of North Sea crudes used to set the Brent price. Still, production of the grades used to price Brent is expected to drop by half—to 500,000 barrels a day—by 2025 because of a lack of investment and fields winding down.

The Brent benchmark’s main competitor, U.S. West Texas Intermediate, is backed by much higher volumes of crude. Around 4 million barrels a day of U.S. crude, which represents around 4% of global production, meets the quality requirements needed for delivery against WTI futures.

Some researchers, including the Oxford Institute for Energy Studies, believe that the Brent benchmark could eventually include U.S. crude to set the price.

Meanwhile, Shell is set to decommission the Charlie platform sometime next year. “There’s a tear in your eye when we’re removing the big ones,” says Shell’s Mr. Lawrie, referring to the platforms. “But it’s a natural part of the life-cycle of the industry we work in.”

Updated: 3-16-2020

After A Long Fall In Oil Prices, A Crash

Oil’s plunge has eroded hundreds of billions of dollars in market value from producers globally, fueled speculation about bankruptcies and mergers.

For Rebecca Babin, the oil crash arrived slowly, then all at once.

The senior energy trader at CIBC Private Wealth Management watched crude prices fall 10% March 6 after Saudi Arabia couldn’t convince Russia to join a plan for deeper supply cuts. The next day’s escalation in the feud sent the 42-year-old scrambling to alert her team, adjust their models and prepare for the opening of trading Sunday evening.

When trading began, U.S. crude oil tumbled from $41 a barrel to around $30 in a matter of minutes, going on to post its biggest one-day drop since the first Gulf War in 1991. Ms. Babin said she woke up every two hours Sunday night to stay abreast of the turmoil, which now has investors who rode out oil’s spike to $145 in 2008 preparing for one of the world’s key commodities to trade at a fraction of that price moving forward.

“There were elements of it that were unlike anything I’ve experienced,” she said. “This is clearly a change to how the commodity is going to trade for the foreseeable future.”

Oil went on to swing wildly in the low $30s in another turbulent week in global markets, ending the week at $31.73. Its plunge has eroded hundreds of billions of dollars in market value from producers around the world and fueled speculation about bankruptcies and mergers. Skepticism about energy companies’ ability to pay a heavy debt burden is also driving concerns that oil’s fall will hurt lenders and exacerbate the economic slowdown resulting from the coronavirus.

While consumers are enjoying the lowest fuel prices in years, analysts say it is too early to count on a demand boost from the energy crash. Companies are already reducing spending, and the transportation restrictions resulting from the coronavirus will likely dull the typical increase in travel one would expect with fuel costs dropping. Research firm Capital Economics projects the drop in drilling investment to more than offset the boost in gasoline consumption in calculating second-quarter U.S. economic growth.

For Americans who lived through the oil-price spikes of 1973 following the Arab oil embargo, 1979 after the Iranian revolution and the 1990 Gulf crisis, the concept of slumping crude being a negative economic signal seems perplexing. Many remember gasoline shortages snarling transportation and the oil-price spike above a record $145 in July 2008 that preceded the financial crisis.

Since then, horizontal drilling and hydraulic fracturing techniques spurred a historic production boom that made the energy industry an integral part of the U.S. economy and supported states from Texas to North Dakota. Soaring shale output powered the U.S. ahead of Russia and Saudi Arabia to become the world’s largest producer of oil and gas.

Banks lent heavily to energy producers, helping many survive the sector’s last major downturn after Saudi Arabia cut prices in 2014 to challenge the shale boom. Oil companies are a key chunk of the high-yield bond market, meaning many investors fear a wave of defaults and bankruptcies that could contribute to further market stress.

“It’s an oil crisis upside down,” said Regina Mayor, who leads KPMG LLP’s energy practice. “My clients are trying not to panic…. It’s a drive to the bottom, and it’s not good for anyone.”

Saudi Aramco slashed most of its prices recently by $6 to $8 a barrel, and Saudi officials have said the kingdom plans to increase output. The move came after Russia refused to accept deeper supply curbs at a meeting earlier this month in Vienna. The Wall Street Journal reported that Saudi pleas for deeper cuts alienated both Russian President Vladimir Putin and his energy minister Alexander Novak.

The clash is an unprecedented shift because supply is expected to increase significantly during a sizable demand drop. After the two nations coordinated oil supply as part of a price-stabilizing alliance between the Organization of the Petroleum Exporting Countries and other nations starting in 2016, their shift to a price war focused on market share threatens to amplify pressure on global growth.

“We’re at a different way of looking at things,” said Darwei Kung, head of commodities and portfolio manager at DWS Group. “We’re cautious in terms of our positioning.”

Companies including Occidental Petroleum Corp., Marathon Oil Corp., Diamondback Energy Inc. and Apache Corp. have pledged to curb spending in response to the splintering of the Saudi-Russia alliance. Billionaire shareholder activist Carl Icahn has bought more Occidental shares as they plummet, doubling down on his fight to take control of the embattled company, The Wall Street Journal reported.

Shares of S&P 500 energy companies recently hit their lowest level in more than 15 years, while Exxon Mobil Corp. and Chevron Corp. have together lost about $200 billion in market value already this year.

The industry’s latest challenge also reflects sudden investor skepticism that institutions from OPEC to governments and central banks can keep the economy balanced in response to the coronavirus. Entering the year, most Wall Street analysts expected oil to stay in its longstanding trading range, projecting U.S. crude between about $50 and $60.

As hedge funds and other speculative investors increased wagers on rising prices, they hit a peak above $63 on Jan. 6 after a U.S. airstrike killed a high-ranking Iranian military leader.

In the two months since then, they have been sliced nearly in half, leading cascading declines across global markets. The S&P 500 is in bear-market territory, defined as a drop of 20% from a recent peak, and on Thursday ended an 11-year bull-market run that drove the index up about 300%.

Meanwhile, the yield on the benchmark 10-year U.S. Treasury note, which affects everything from auto loans to mortgage debt, tumbled to a record low of 0.5% last Monday from 1.91% at the end of last year. It ended the week at 0.95%. Those moves in tandem with tumbling raw-materials prices are sending a worrying economic signal to many investors.

“Oil declining dramatically is a telltale sign that the industrial economy is in trouble,” said Gary Ross, chief executive of Black Gold Investors LLC and founder of consulting firm PIRA Energy Group.

This week’s latest market malaise began last Sunday evening when oil-futures trading began at 6 p.m. ET. Prices fell around $30 a barrel before trimming some of that slide, but the damage quickly began rippling across asset classes. U.S. stocks fell hard enough at the open Monday morning to trigger a circuit breaker for the first time in 23 years that kept trading frozen for 15 minutes.

“Nobody was saying it was going to open at $30,” said Robert Yawger, director of the futures division at Mizuho Securities U.S.A. in New York. “It’s a nasty situation.”

Now, investors are weighing how much further oil prices can fall. U.S. crude fell to $26 in February 2016 before recovering as the Chinese economic outlook improved and OPEC cut supply. Four years later, analysts say they are struggling to find a similar solution.

“I couldn’t think of anybody who warned of this,” said Gene McGillian, vice president of research at Tradition Energy in Stamford, Conn. “The world, if it wasn’t for the production agreement, is awash in oil.”

Rob Thummel, a senior portfolio manager at Leawood, Kan.-based investment firm Tortoise, said he still thinks prices will recover in the long term because large producers need them to support their economies. But the OPEC surprise has him bracing for more big swings for now.

“It’s a complete shock to everyone,” he said. “This is all fear and anxiety.”

Updated: 3-16-2020

Oil Crash Is Bad News for Regional Banks That Went Big on Energy

Problems of energy companies could be passed on to their lenders.

Lenders are bracing for loan losses and depressed earnings from an oil crash that is bruising the North American energy industry.

U.S. and Canadian banks have more than $100 billion in loans outstanding to energy companies. An oil-price crash set in motion by Saudi Arabia earlier this month could cause many of those energy companies to struggle to make good on those loans.

Especially vulnerable are regional banks with big energy-lending portfolios. Larger banks also are on the hook for billions of dollars in loans to the energy industry, but they are relatively less exposed because their balance sheets are much bigger and their lending businesses more diversified. Energy accounts for 3.2% of Citigroup Inc.’s loan portfolio and 2.1% of JPMorgan Chase & Co.’s loan book, according to Goldman Sachs analysts.

But a shakeout among regional banks’ borrowers could dent their earnings this year between an average of 15% to 60%, depending on the extent of loan losses, said Keefe, Bruyette & Woods analyst Brady Gailey.

“It is a big deal for these oil-exposed banks,” he said.

U.S. benchmark prices ended the week at $31.73. a barrel, 23% below their level on March 6.

Prices still have a long way to fall to match the extended decline between 2014 and 2016, when prices for the benchmark West Texas Intermediate grade fell to $26 a barrel from $106. That decline battered the stocks of energy lenders and forced them to increase their credit reserves to guard against defaults.

A spate of energy companies filed for bankruptcy during the last crash to pare their debt; in the years since, they have piled it back on. In addition to their bank loans, North American oil and gas exploration and production companies have “a staggering” $86 billion of rated debt coming due between 2020 and 2024, Moody’s Investors Service said in a February report.

Those lofty debt levels could become a big problem if prices stay low for a while, leading to a new round of defaults and bankruptcy filings that could result in loan losses.

Bank investors are expecting fallout. The KBW Nasdaq Regional Banking Index has fallen almost 14% since March 6, just before Saudi Arabia launched the oil-price war. While much of that decline can be traced to the broader market rout, banks with the biggest relative exposures to the energy industry have fallen even more. Some have lost a quarter of their market value since the March 6 close.

Bank of Oklahoma parent BOK Financial Corp. is among them. Loans to energy companies such as deeply indebted Whiting Petroleum Corp. account for some 18% of its lending book. The bank’s shares have fallen 22% from March 6 through Friday’s close.

The bank should be able to weather the rout in the short term, BOK chief financial officer Steven Nell said Tuesday in a filing with the Securities and Exchange Commission. The outlook is cloudier if oil prices stay low for a year or longer.

“At that point, we would be more likely to see loss content in the portfolio and a greater impact on the overall economy, and in turn lower loan demand,” Mr. Nell said in the filing.

Cullen/Frost Bankers Inc. has reduced its exposure to energy borrowers since 2015, during the last big plunge in energy prices. Still, 11% of the San Antonio-based bank’s loan portfolio was dedicated to energy companies at the end of 2019.

The bank reported a more than 50% increase in problem energy loans in the fourth quarter from the third. In January, before prices crashed, CEO Phillip Green said the bank expected higher charge-offs in the sector later this year. The bank’s stock fell almost 10% through Friday. A bank spokesman said the bank was confident in its lending standards. “We’ve been through worse things than this before,” he said.

The energy industry will face a reckoning in the spring, when banks embark on their twice-yearly reassessment of the value of the oil and gas reserves that serve as collateral for their loans.

These loans were last evaluated in the fall, when crude prices were above $50 a barrel. If prices remain in the $30s or keep falling, much of the oil won’t be economical to extract, meaning companies can no longer borrow against it and must repay banks.

For energy companies already struggling with big debt burdens and shrinking cash flows, a bank’s sudden demand for repayment or a reduction in their borrowing capacity can set off a spiral into default.

The borrowing-base redeterminations, as they are known, could pose a problem for banks like Dallas-based Comerica Inc. The bank has reduced the size of its energy portfolio by $1.3 billion since 2015; energy loans now account for 4.5% of its loan book, said CEO Curtis Farmer at a banking conference on Tuesday. Still, should prices stay low, its borrowers could lose access to credit.

“The ultimate outcome will depend on the duration of the cycle,” Mr. Farmer said.

Losses of 5% in its energy portfolio could depress Comerica’s 2020 earnings per share by 9%, according to KBW. A spokesman said the bank lost an average 1.5% per year in its energy loan book between 2015 and 2017.

Updated: 4-1-2020

Trump To Meet With Oil CEOs About Helping Industry

Steep oil-price drop has U.S. industry reeling.

President Trump is set to meet Friday with the heads of some of the largest U.S. oil companies to discuss government measures to help the industry weather an unprecedented oil crash, people familiar with the matter said.

The meeting is to take place at the White House and will include Exxon Mobil Corp. Chief Executive Darren Woods, Chevron Corp. Chief Executive Mike Wirth, Occidental Petroleum Corp. Chief Executive Vicki Hollub and Harold Hamm, executive chairman of Continental Resources Inc., the people said.

The U.S. oil and gas industry has been pummeled recently by the dual shock of plummeting oil demand because of the coronavirus pandemic and surging supply as Russia and Saudi Arabia are locked in a price war and flood the market with crude.

Oil prices plunged this week to just above $20 a barrel, the lowest level in nearly two decades.

Mr. Trump and the executives are set to discuss potential aid to the industry, including tariffs on oil imports into the U.S. from Saudi Arabia, and a waiver of a law that requires American vessels be used to transport goods, including oil, between U.S. ports, according to two of the people.

But the oil industry isn’t unified in its support for some of the measures, the people familiar with the matter said. Only Mr. Hamm supports oil tariffs, according to the people. A temporary waiver of the Jones Act, which would allow U.S. ships to transport oil around the country, could represent a compromise and earn the backing of the other companies, one of the people said.

Such a waiver would allow U.S. oil to be shipped from the petrochemical hub on the Gulf Coast to markets on the East Coast and Washington state, which are currently being flooded with imports from Saudi Arabia. The U.S. has previously granted such waivers, typically for about 10 days, during other emergencies.

Updated: 4-1-2020

Whiting Petroleum Becomes First Major Shale Bankruptcy As Oil Prices Drop

The filing comes as many U.S. oil drillers face pressure to meet hefty debt obligations.

U.S. shale driller Whiting Petroleum Corp. filed for bankruptcy protection on Wednesday, becoming the first sizable fracking company to succumb to the crash in oil prices.

Whiting’s bankruptcy filing comes as many U.S. oil drillers face pressure to meet hefty debt obligations they took out from banks and bondholders to make America into the world’s largest oil and gas producer, as U.S. benchmark crude prices drop to their lowest levels in nearly two decades.

Oil prices are coming off their largest monthly drop ever as the coronavirus pandemic saps oil demand at the same time Saudi Arabia presses a price war against Russia by flooding global markets with crude. The price deterioration has pushed many U.S. shale companies to the brink of bankruptcy and upended efforts by those already in chapter 11 to restructure their operations.

If the downturn persists, a number of U.S. drillers could default on more than $32 billion of high-yield debt over this year, with a projected default rate of 17%, according to credit-ratings firm Fitch Ratings. Before crude tanked, Fitch had forecast a 7% default rate for 2020.

Last year, 41 U.S. oil companies filed for bankruptcy protection in cases involving $11.7 billion in debt, according to Dallas law firm Haynes & Boone.

With U.S. crude trading at around $20 a barrel—down from above $60 a barrel in January—dozens of U.S. shale producers are at risk of breaching debt covenants as their ratios of debt to pretax earnings balloon to untenable levels. To make matters worse, equity and debt markets that recapitalized producers in the last downturn a few years ago have largely closed to U.S. oil companies after years of poor returns, said Shawn Reynolds, portfolio manager at investment manager VanEck.

“There’s hardly anything you can do,” outside of restructuring debt, Mr. Reynolds said.

Whiting sought chapter 11 protection in U.S. Bankruptcy Court in Houston, after some bondholders agreed to swap $2.2 billion in debt for a 97% equity stake in the reorganized company.

Whiting said it needed to file for bankruptcy in part over worries that the company’s borrowing capacity on a $1 billion loan would be cut.

In court on Wednesday, Whiting lawyer Brian Schartz said the company thought the borrowing base wouldn’t go “anywhere but down.” He said the company was still rounding up the required support from creditors for the debt-for-equity swap.

Bankruptcies in the U.S. oil patch are expected to gain momentum in the second quarter, accelerating as some drillers are forced to shut in production amid reduced oil demand and low available storage capacity, said Buddy Clark, a partner and co-chair of energy practice group at Haynes & Boone.

“It’s a dire situation for everyone,” Mr. Clark said, noting that even bankruptcy courts are struggling to operate amid the pandemic and are under pressure from an influx of new cases. “It’s a weird dynamic, but people will want to get into bankruptcy quickly in order to beat the rush.”

A number of oil-and-gas companies, including Chesapeake Energy Corp., Ultra Petroleum Corp. and California Resources Corp., have either warned they may not stay current on their debts or hired restructuring advisers to negotiate with creditors.

Denver-based Whiting, one of the largest drillers in North Dakota’s Bakken Shale, had come under financial pressure even before U.S. crude prices collapsed.

Chief Executive Brad Holly said the company’s proposed restructuring was its “best path forward” given uncertainty about how long the Saudi-Russia price war and the coronavirus pandemic would go on.

Whiting foreshadowed its bankruptcy by taking steps on Friday to protect $3.4 billion in net operating losses, which are potentially valuable tax assets that could be used to reduce future federal taxes.

The company also drew down $650 million from its loan facility last week to generate cash and won’t make a $262 million debt payment that comes due Wednesday. The maturing bond has lost more than 90% of its value since mid-February, according to MarketAxess, and closed at 6 cents on the dollar on Wednesday.

Before the bankruptcy, Whiting’s top five executives got board approval for $14.5 million in cash payments last week, including $6.4 million for Mr. Holly, according to a regulatory filing. The executives would be required to waive their participation in a previous bonus program and forfeit equity awards granted earlier this year.

Under Whiting’s restructuring proposal, top executives are in line to receive up to 8% of the stock in the reorganized company when it emerges from bankruptcy. Mr. Holly and other insiders together own less than 1% of the company, according to data from FactSet.

Updated: 4-13-2020

Baker Hughes Pursues $1.8 Billion Restructuring Plan Amid Oil-Price Declines

Oilfield-services company expects to book $15 billion in noncash goodwill impairment.

Baker Hughes Co. BKR 3.50% said it is pursuing a restructuring plan that will result in about $1.8 billion in charges and expects to book a roughly $15 billion goodwill impairment charge for the first quarter as the company faces the coronavirus pandemic and declines in oil and gas prices.

The oil-field services company said Monday it will book $1.5 billion of those charges for the first quarter. Future cash expenditures related to those charges are projected to be about $500 million with an expected payback within a year, it said.

Baker Hughes said it conducted an interim quantitative-impairment test as of March 31 due to uncertainty in oil demand and its effect on investment and operating plans of the company’s customers. The test concluded that the oilfield-services and oilfield-equipment reporting units’ carrying value exceeded their estimated fair value, resulting in a noncash goodwill impairment charge.

The company also said it plans to cut 2020 capital expenditures by more than 20%. It had $3 billion in cash and cash equivalents for the year ended Dec. 31, 2019.

A standoff between Saudi Arabia and Russia over production cuts and a sharp drop in demand caused by the pandemic have led to a big decline in oil prices. The number of rigs drilling in the U.S. has fallen to about 600, down from nearly 800 a month ago, according to Baker Hughes.

After reducing its stake in 2019, General Electric Co. no longer controls Baker Hughes or counts its financial results or staff as its own.

Updated: 4-13-2020

North America’s Oil Industry Is Shutting Off the Spigot

Energy producers are resorting to the desperate measure of shutting in productive oil wells.

Canceled orders were mounting when Texland Petroleum LP recently decided to shut in each of its 1,211 oil wells to cease production by May.

“We’ve never done this before,” said Jim Wilkes, president of the 7,000-barrel-a-day Fort Worth, Texas, firm, which has weathered oil busts since 1973. “We’ve always been able to sell the oil, even at a crappy price.”

Now there are no buyers for the crude coming from its wells and no choice but to shut them in. Texland told state regulators its plans and applied for a loan through the Small Business Administration’s Paycheck Protection Program to keep its 73 employees on payroll.

From the West Texas desert, where oil is blasted from deep shale formations, to the wilds of western Canada, where multibillion-dollar steam plants bubble thick crude from the earth’s crust, energy producers are resorting to the desperate measure of shutting in productive wells.

Though President Trump promised the U.S. would curtail oil output in a pact with major producers, including Saudi Arabia and Russia, there is really no mechanism for the federal government to do so without legislation or major regulatory changes, such as tougher environmental enforcement. Instead, U.S. producers are choking back on their own due to the dismal economics and strained physics of the oil market.

The sharp drop in fuel consumption caused by the coronavirus pandemic and exacerbated by the feud between the world’s largest producers has limited options for North American oil companies. Pipelines, refiners and storage facilities are filling up. Even when there is somewhere to send oil, low prices mean that many barrels lose money.

West Texas Intermediate, the main U.S. price benchmark, closed Monday at $22.41 a barrel, down 63% since the start of the year. It has been even worse in Midland, Texas, where a lot of oil extracted from the Permian Basin is priced, and in western Canada, from which most of the country’s output comes. Oil has traded below $10 a barrel in both markets.

Since mid-March, producers ranging from Exxon Mobil Corp. and Royal Dutch Shell PLC to Oklahoma City’s Devon Energy Corp. and Cenovus Energy Inc. of Calgary, Alberta, collectively have announced spending cuts totaling some $50 billion.

The number of rigs drilling in the U.S. has fallen to about 600, down from nearly 800 a month ago, according to Baker Hughes Co. Drilling is always down in Canada this time of year, when the spring thaw hinders accessibility, but the 35 rigs operating there are the fewest Baker Hughes has ever counted.

It can take months for the flow from new wells to taper off, so production has only begun to reflect the austerity. U.S. production has declined about 5% from March’s record levels, according to the Energy Information Administration.

The drop in demand has been steeper, with factories idled, flights grounded and billions of people around the world under stay-at-home orders to fight the spread of the deadly virus. Analysts forecast oil consumption declining by at least 20 million barrels a day, representing roughly 20% of global demand.

Daily consumption of petroleum products in the U.S. fell 19% during the week ended April 3 to what is at least a 30-year low, the EIA said. Domestic crude inventories swelled by the biggest weekly increase on record.

At that rate, the world would run out of places to put oil within about 60 days, analysts with Houston’s Simmons Energy estimate. Some analysts think the world’s storage caverns, tank farms, pipelines, refineries and ships will fill even faster.

Alberta’s energy minister, Sonya Savage, said Sunday’s pact by major producers could slow the march to an eventual topping out of storage tanks, which are close to full in Canada. “It’s getting close,” she said, adding that the status quo that existed before these talks was “unsustainable.”

Canada has room for fewer than four days’ worth of production, energy data provider Genscape Inc. estimates. In the U.S., there is much more storage capacity, but it isn’t evenly available to producers.

A refiner teeming with, say, jet fuel, may not be able to take in more crude from its suppliers even if there is demand for other products, like diesel. Backed-up pipelines could strand barrels.

“We‘ve been told by two of my markets they won’t take my production in May because there’s nowhere to put it,” said Russell Gordy, a Texas oilman with wells in his home state, Colorado, Wyoming and the Gulf of Mexico. “We won’t have to shut in everything, but we’ll have to shut in most of our production.”

Larger companies are shutting in wells too. Continental Resources Inc., which drills in Oklahoma and North Dakota, said it would reduce output in April and May by about 30%.

In West Texas, Parsley Energy Inc. has shut in about 150 older wells that together produced about 400 barrels a day, and were no longer worth the expense of powering the equipment inside, daily maintenance and paying out royalties, said Chief Executive Matt Gallagher.

Output from newer shale wells can be reduced without shutting them in entirely. But those big wells, with horizontal bores that stretch for miles, usually produce oil at the lowest costs, which makes choking them back unappetizing to producers scratching for every penny.

Canadian producers have eliminated roughly 325,000 barrels of daily output, according to consulting firm Rystad Energy, which predicts ultimate declines of about 1 million barrels, or nearly 25%. Suncor Energy Inc. has shut down one of two production lines at its 200,000-barrel-a-day Fort Hills oil sands mine in northern Alberta. Others have capped smaller wells.

“We have small companies that have shut every drop in,” said Kent McDougall, chief commercial officer at Alberta oil trucker Torq Energy Logistics.

Producers are doing so without knowing what will happen when they try to resume production.

Canadian crude is often called bitumen, which is as thick as peanut butter unless it is heated. Producers shovel up reserves close to the surface, but deeper deposits are coaxed out by injecting steam underground. Shutting down such operations is risky and expensive. Restarting them is touchy. It can take a long time to warm up the wells to resume flow, and there’s no guarantee they will be as productive.

In the U.S., the risks usually have to do with water. It can flood reservoirs, alter pressure and, since deep groundwater is salty, corrode components downhole.

That is what worries Texland’s Mr. Wilkes. The company has no experience restarting its wells and he can only guess what problems might arise once the artificial lift systems in its wells are powered down.

“Some wells may take time to recover to their previous production rate,” he said. “Some may never recover.”

Updated: 4-14-2020

Thirst For Oil Vanishes, Leaving Industry In Chaos

As people stay home to avoid the new coronavirus, the petroleum business is ‘experiencing a shock like no other in its history’.

No one expected 2020 would unleash a world-wide oil-production cut led by the U.S., Saudi Arabia and Russia. But since the new coronavirus hit, the world’s thirst for oil has vanished, creating an unprecedented crisis for one of the planet’s most powerful industries.

With billions of people in lockdown to avoid the virus, crude-oil demand has collapsed as people stop driving and airplanes are grounded.

There is too much gasoline and jet fuel on the market, so refineries that turn crude into fuel are slowing oil purchases. Oil-storage facilities from Asia to Africa and the American Southwest are filling up. Producers have begun to shut in wells whose oil has nowhere to go.

The result is a breakdown of parts of the supply chain that delivers one of the world’s most important commodities. “The global oil industry is experiencing a shock like no other in its history,” said Fatih Birol, executive director of the International Energy Agency.

Over the weekend, a coalition of nearly two dozen of the world’s largest oil-producing countries agreed to withhold 9.7 million barrels a day from markets. It is unclear if this level of coordinated cuts is enough to erase the glut. Mohammed Barkindo, secretary-general of the Organization of the Petroleum Exporting Countries, has described the fundamentals in the oil market as “horrifying.”

Global demand for crude is normally around 100 million barrels a day. Estimates of the decline vary widely and change daily, but most put current demand at 65 million to 80 million barrels a day. In volume and percentage, the fall exceeds the collapse of 1979 to 1983. It occurred over four weeks, not four years.

‘This Is Uncharted’

“Since humans started using oil, we have never seen anything like this,” said Saad Rahim, chief economist at Trafigura Group Pte. Ltd., a Singapore commodity-trading company that estimates demand at 65 million to 70 million barrels a day. “There is no guide we are following. This is uncharted.”

Not Thirsty

Crude-oil demand has fallen in an unprecedented manner, sending the global oil industry into a tailspin.

For weeks, the industry has been producing more than $500 million a day of crude no one wants to buy. The U.S. benchmark oil price, West Texas Intermediate, fell to just above $20, an 18-year low, at the end of March. It closed Monday at $22.41, down 63% from the year’s start.

Prices in some other hubs are substantially lower. In western Canada, oil closed Monday at $3.16 a barrel, down 84% from a month earlier.

“If you buy a cargo today, as a trader, you are not sure you will ever find a buyer for it because everyone has too much oil,” said Torbjörn Törnqvist, chief executive of Gunvor Group Ltd., which trades energy products in more than 100 countries. He worries that, in a couple of weeks, global energy markets will become “dysfunctional.”

Behind it all is the decision by governments to order or urge citizens to stay home. Normally, about 60% of the world’s oil goes toward making transportation fuels. Now, traffic counters and satellite images show a world immobilized.

Outside Milan, the normally jostling crowds at the Carosello mall were replaced by a smattering of shoppers, according to Paris-based satellite-data company Kayrros. In late March, vehicle crossings at San Francisco’s Golden Gate Bridge fell 71% from a year earlier, a bridge spokeswoman said. The global aviation industry’s number of seats for sale as of April 13 was a third that in January, according to OAG, an aviation industry data firm.

Oil producers have been slow to react. It can be difficult and expensive to turn off an oil field and turn it back on. No one wants to be first to cut, and cede market share, so a global game of chicken is playing out.

Thin Air

Airline operations have contracted significantly since January 20th, as measured in passenger seats.

In South Africa, the giant Saldanha Bay oil-storage terminal is full, said Trafigura’s Mr. Rahim. The government agency operating the tank farm didn’t respond to inquiries.

Earlier this year, Kevin Foxx’s four cylindrical tanks capable of holding a total 700,000 barrels of crude in the Cushing, Okla., area—the main pipeline-and-trading hub in North America—were less than half full. Now, the chief executive of Barcas Pipeline Ventures LLC said he expects them to be filled by this month’s end.

When Cushing fills, pipelines from the Permian Basin and Gulf Coast will have to order shippers to stop adding crude.

The system, Mr. Foxx said, will reach its limit. “Nothing is available,” he said. “If there’s nowhere to go in Cushing, if the pipelines are full, now we’re backed up to the producer.”

Colonial Pipeline Co., whose 5,500-mile conduit carries gasoline from Gulf Coast refineries into the Washington, D.C., and New York metro areas, issued a stern reminder in mid-March: Shippers couldn’t put gasoline into the nation’s largest fuel-conveyance system if they didn’t have contracted buyers. Operators like Colonial don’t want their pipelines to become parking lots for fuel.

While the pandemic has battered many industries, repercussions are likely to be long-lasting for global oil. Demand had plummeted during an existing oversupply, exacerbated by a price war between Russia and Saudi Arabia that broke out as the coronavirus was taking hold. Last month, Saudi Arabia increased production, saying it would raise output more than 2.5 million barrels a day to 12.3 million, before reversing course earlier this month.

Great Depression

The only time the combination of falling demand and a supply increase was even close to the current situation was in the 1930s with the discovery of the giant East Texas oil fields during the Great Depression. Crude fell to 24 cents a barrel in August 1931, a little more than $4 adjusted for inflation; demand declined gradually over several years.

In response, the Railroad Commission of Texas started regulating output, beginning decades of government interventions in global oil markets. Texas hasn’t curtailed oil production for more than a half-century, but the state agency served as the model for OPEC. Texas regulators say they are debating whether to cut state output again.

Optimists such as energy economist Philip Verleger believe the industry will be able to regain its footing once virus-related lockdowns are lifted and people begin to move again.

“The current downturn is harsh, but probably not the worst ever, especially if the global economy rebounds as many expect,” he said. Still, he believes one has to go back to the 1930s to find anything comparable. “We haven’t seen a demand shock like this in 90 years,” he said, adding that the 2020 contraction has been much quicker than during the Great Depression.

Prices remain below what most companies need to operate existing wells without losing money. In a recent Federal Reserve Bank of Dallas survey, oil operators estimated it cost them $26 to $32 to produce a barrel from an existing well in the Permian Basin of West Texas and southeastern New Mexico.

At $20, operators across the basin would lose a combined $200 million a week, an analysis of data that producers reported to the Dallas Fed suggests.

Whiting Petroleum Corp. filed for bankruptcy protection this month, the first major producer to fall this crisis. Energy analytics firm Rystad Energy said that at $30 oil, more than 70 U.S. oil-and-gas producers could have trouble making interest payments on their debt this year; at $20 crude, it would increase to about 140 companies.

“It’s a Grand Canyon of a supply-demand void,” said Matt Gallagher, chief executive of Parsley Energy Inc., a major Permian oil producer. Parsley, along with many other Permian producers, is shutting down uneconomic wells and has cut its planned capital expenditures this year to conserve cash. Mr. Gallagher is urging the U.S. government to impose a two-to-three-month embargo on importing some overseas crude, which would effectively reverse several decades of U.S. policy encouraging the free flow of global oil.

Mr. Gallagher has reason to worry: As part of its battle to capture market share, Saudi Arabia has a flotilla of cut-rate crude en route to the U.S. and Europe. The world’s largest oil exporter, it went on an early-March ship-hiring spree in Singapore, where many giant tankers called Very Large Crude Carriers, or VLCCs, were unchartered amid collapsing demand.

Within days, it had leased 24 supertankers, said Anoop Singh, head of tanker research in Asia at Braemar ACM Shipbroking Ltd. “They wanted it first,” he said, “they wanted it quick.”

Several VLCCs are now sailing toward Houston and could further inundate the U.S. market.

Storage Is Power

In a world of excess supply, controlling storage is power, and Saudi Arabia has become king of it. Oil stored inside the country rose by 8 million barrels to 79 million in 2½ weeks before March 26, according to satellite firm Kayrros.

The Saudis booked remaining capacity in an Egyptian storage facility, according to Saudi officials and traders. Still, demand fell faster than it could lease storage. In late March, as India entered lockdown, Indian Oil Corp., the country’s largest oil refiner, cut its output one-third. A Saudi energy-ministry spokesman didn’t return requests for comment.

If Saudi Arabia isn’t able or willing to return to its role as the globe’s central bank of oil—cutting output when the market is oversupplied, adding when undersupplied—then an untethered and volatile market will dictate prices.

“We are just going to have to buckle up,” said Bob McNally, a former energy adviser to President George W. Bush and author of “Crude Volatility,” a study of oil’s boom-and-bust cycles, “and learn to run the world with Space Mountain oil price cycles.”

Updated: 4-15-2020

Glutted Oil Markets’ Next Worry: Subzero Prices

Traders of physical barrels of crude brace for the possibility of negative pricing; traders of energy derivatives also wary.

The coronavirus pandemic is turning oil markets upside down.

While U.S. crude futures have shed half of their value this year, prices for actual barrels of oil in some places have fallen even further. Storage around the globe is rapidly filling and, in areas where crude is hard to transport, producers could soon be forced to pay consumers to take it off their hands—effectively pushing prices below zero.

The collapse is upending the energy industry and even the math used in trading energy derivatives. CME Group, the world’s largest exchange by market capitalization for trading futures and options, now says it is reprogramming its software in order to process negative prices for energy-related financial instruments.

Part of the problem, traders say, is the industry’s limited capacity to store excess oil. Efforts to curb the spread of the virus have driven demand to record lows. Factories have shut. Cars and airplanes are sitting immobile. So refineries are slashing activity while stores of crude rapidly accumulate.

U.S. crude inventories surged by a record 15.2 million barrels during the week ended April 3, according to data from the Energy Information Administration. Gasoline stockpiles also jumped, climbing by 10.5 million barrels, while refining activity hit its lowest level since September 2008.

The buildup of crude is overwhelming storage space and clogging pipelines. And in areas where tanker-ship storage isn’t readily available, producers could need to go to extremes to get rid of the excess, said Jeffrey Currie, head of commodities research at Goldman Sachs. Those might include paying for it to be taken away.

“It’s like traffic on a freeway,” he said. “It gets congested when there are a lot of cars.”

Crude comes in many varieties, used for a range of purposes, and different grades are priced based on several factors, including their density, sulfur content and ease of transportation to trading hubs and refineries. Heavier, higher-sulfur crudes generally trade at a discount to lighter, sweet crudes such as West Texas Intermediate because they tend to require more processing. Crudes that depend on pipeline transportation are trading at a discount right now because there is nowhere to put them and the pipelines that would normally take them away are getting jammed up, analysts and traders say.

The price of some regional crudes recently dipped into single digits. The spot price of Western Canadian Select at Hardisty—a heavy grade of Canadian crude typically transported by pipeline or rail to the U.S. Gulf and Midwest for refining—fell to just over $8 a barrel on April 1, according to an assessment from S&P Global Platts.

The spot price of West Texas Intermediate at Midland fell to just above $10 a barrel on March 30, while West Texas Sour at Midland—its harder-to-refine counterpart—fell to around $7 a barrel. And one commodities trading house recently bid less than zero dollars for Wyoming Asphalt Sour crude.

It isn’t just the traders of so-called physical oil who are bracing themselves for the possibility of negative pricing. Traders of energy derivatives are preparing, too. Mark Benigno, co-director of energy trading at INTL FCStone, said he has never seen oil derivatives trade below zero but began several weeks ago to assess what might happen if they do.

“It’s something we have to consider,” he said. “Options are structured to go to zero. That puts a limit on how much you can lose. When they go below that, it becomes a different situation entirely.”

In recent weeks, traders have pinned hopes for a rebound on the Organization of the Petroleum Exporting Countries and other oil-producing nations.

Over the weekend, Saudi Arabia and Russia ended a production feud and joined the U.S. to lead a coalition of 23 oil-producing countries to cut output by a collective 9.7 million barrels a day. The feud began in March after Russia refused to participate in a Saudi-backed plan to carry out coordinated cuts. Saudi Arabia then lowered prices and raised production of its barrels, sending global prices into a downward spiral.

However, traders and analysts say the demand lost due to the coronavirus far exceeds the supply cuts.

“It’s not nearly enough to make a significant shift in balancing the market,” said Chris Midgley, global head of S&P Global Platts Analytics.

U.S. benchmark prices tumbled 10% on Tuesday and are down 67% so far this year.

Prices could get a boost as energy producers are forced to shut off the taps, analysts and traders say. The fall in oil prices has hit producers hard. Chevron Corp., Exxon Mobil Corp. and Diamondback Energy Inc. have pledged to slash spending. U.S. shale driller Continental Resources Inc. recently said it would cut its output by around 30% in April and May and suspend its quarterly dividend. Denver-based Whiting Petroleum Corp. filed for bankruptcy.

Some analysts see a glimmer of hope coming from China, where there are some signals of life returning to normal. Chinese consumers have cautiously begun to travel again after hunkering down at home for two months.

Others aren’t as optimistic, noting that global oil demand is still falling by tens-of-millions of barrels a day.

“We really don’t know when demand will come back online,” said Rusty Braziel, chief executive of RBN Energy.

Updated: 4-20-2020

U.S. Oil Costs Less Than Zero After A Sharp Monday Selloff

Many traders are betting that the coronavirus pandemic will run its course and demand for oil will jump later this year.

U.S. oil futures plunged below zero for the first time Monday, a chaotic demonstration that there was no place left to store all the crude that the world’s stalled economy would otherwise be using.

The price of a barrel of West Texas Intermediate crude to be delivered in May, which closed at $18.27 a barrel on Friday, ended Monday at negative $37.63. That effectively means that sellers must pay buyers to take barrels off their hands.

The historic low price reflects uncertainty about what buyers would even do with a barrel of crude in the near term. Refineries, storage facilities, pipelines and even ocean tankers have filled up rapidly since billions of people around the world began sheltering in place to slow the spread of the deadly coronavirus.

Prices remain in positive territory for barrels to be delivered in June. In the most actively traded U.S. futures contract, crude for June delivery closed Monday at about $21, while oil due to be delivered to the main U.S. trading hub in Oklahoma in November ended at around $32.

Even before May’s price went negative, the spreads between oil now and later were records, reflecting the sharp decline in transportation-fuel demand as well as a wager that people will return to driving cars, flying on airplanes and working at factories in the months to come.

Monday’s chaotic trading was exacerbated by the looming expiration of the May futures contract on Tuesday. The price of oil futures converge with the price of actual barrels of oil as the delivery date of the contracts approach.

Though producers from Alberta, Canada to Midland, Texas are racing to shut in productive wells, they haven’t been able to close off the spigot fast enough to avoid what energy executives have been referring to as “hitting tank tops” and running out of places to store crude and petroleum products, such as gasoline and jet fuel.

The producers’ pain presents a rare opportunity for traders, who are filling up tankers with crude and setting them adrift. Their bet is that the coronavirus pandemic runs its course and later this year demand for oil—and thus its price—will jump.

“If you can find storage, you can make good money,” said Reid I’Anson, economist for market-data firm Kpler Inc.

Increasingly, traders are looking offshore. Lease rates have soared for very large crude carriers, the 2-million-barrel high-seas behemoths known as VLCCs.

The average day rate for a VLCC on a six-month contract is about $100,000, up from $29,000 a year ago, according to Jefferies analyst Randy Giveans. Yearlong contracts are about $72,500 a day, compared with $30,500 a year ago. Spot charter rates have risen sixfold, to nearly $150,000 a day.

Day rates rise as the spread between oil-futures contracts widens. The basic math is that every dollar in the six-month spread equates to an additional $10,000 a day that can be paid for a VLCC over that time without wiping out all the oil-price gains, Mr. Giveans said.

May delivery futures of Brent crude, the international benchmark typically used to price waterborne oil, ended Friday at $28.08 a barrel. The contract for November delivery settled at $37.17. The $9.09 difference wouldn’t justify a $100,000 day rate, but the record spread of $13.45 reached on March 31 does.

At the end of March there were about 109 million barrels of oil stowed at sea, according to Kpler. By Friday it was up to 141 million barrels.

The collapse in current oil prices, combined with the expectations that a lot of economic activity will resume by autumn, has resulted in a market condition called contango—in which prices for a commodity are higher in the future than they are in the present.

One of the great trades in modern history involved steep contango and a lot of oil tankers. In 1990, Phibro, the oil-trading arm of Salomon Brothers, loaded tankers with cheap crude just before Iraq invaded neighboring Kuwait and crude prices surged. The trade’s architect, Andy Hall, rose to fame, bought a century-old castle in Germany and became known for a $100 million payday.

Present market conditions have inspired emulators.

In the past four weeks, nearly 50 long-term contracts have been signed for VLCCs, Mr. Giveans said. Jefferies has identified more than 30 of them as being intended for storage, usually because they are leased without discharge locations. The coast of South Africa offers popular anchorage since it is relatively equidistant to markets in Asia, Europe and the Americas.

“We’ve seen more floating-storage contracts signed for 12 months in last three weeks than we’ve seen in the last three years,” Mr. Giveans said.

Companies that own and operate pipelines and oil-storage facilities could gain as well.

Consider the difference between Friday’s price for West Texas Intermediate to be delivered in May, which was $18.27 a barrel, and in May 2021, which closed at $35.52: A $17.25 spread could be locked in by buying contracts for oil to be delivered next month and then selling contracts for delivery a year later.

Assuming monthly costs for storage owners of 10 cents a barrel—as Bernstein Research analysts did when they ran back-of-the-envelope storage math in a recent note to clients—leaves a profit of $16.05 a barrel.

Companies don’t usually disclose unused storage capacity, but it is possible that bigger players such as Energy Transfer LP, Enterprise Products Partners LP and Plains All American Pipeline LP could have room for tens of millions of barrels, the Bernstein analysts said.

Updated: 4-21-2020

Oil-Price Crash Deepens, Weighs on Global Markets

Stocks fall as U.S. crude benchmark plunges, a day after one contract fell below zero.

A fresh plunge in oil prices dragged down investments from stocks to currencies Tuesday, stinging investors anew and adding even more urgency to the crisis sweeping the energy industry.

Major U.S. stock indexes have largely shrugged off concerns about bankruptcies and job losses in the energy sector while rebounding from a March 23 multiyear low. But this week’s drops show that recent chaos in the world’s busiest commodity market is beginning to compound lingering worries about the coronavirus.

The most heavily traded U.S. crude-oil futures contract fell 43% Tuesday to $11.57 a barrel, its lowest close in 21 years. Its record low is $10.42 in data going back to 1983. Tuesday’s drop came a day after one contract for U.S. crude fell below zero for the first time in history, forcing sellers to pay buyers to take barrels off their hands.

Anxiety about the crash’s impact on large energy producers from the U.S. to Saudi Arabia helped drag the S&P 500 down 3.1%, bringing the broad equity gauge’s fall for the week to nearly 5%. It is still up more than 20% from its March low, but traders say the energy sector’s struggles could contribute to further falls.

Energy analysts say the scope of the oil demand lost to the coronavirus means there is little producers can do to give prices a short-term boost. President Trumpin a tweet Tuesday said he had directed the Energy and Treasury departments to craft a plan to make funds available for the oil-and-gas industry. “We will never let the great U.S. Oil & Gas Industry down,” he wrote.

The Trump administration is considering offering federal stimulus funds to embattled oil-and-gas companies in exchange for government ownership stakes in the companies or their crude reserves, The Wall Street Journal reported.

Still, government data due Wednesday are expected to show another big increase in oil stockpiles for last week. Texas regulators declined to act Tuesday on a proposal to limit state oil supply, but some shale producers are already being forced to shut in productive wells. The expected supply drops are dwarfed by lost demand.

“Demand is contracting two or three times as fast as supply,” said Bob McNally, president of consulting firm Rapidan Energy. The drop in prices is a “brutal but efficient” mechanism to “persuade producers to keep oil under the crust,” Mr. McNally said.

“The looming question is now how some of these big energy companies are going to stay afloat,” said Mohit Bajaj, director of exchange-traded fund trading solutions at WallachBeth Capital. “People are pointing fingers in the market to the move in oil… It’s a big shift.”

Investors sold everything from energy stocks to currencies of major suppliers like Russia on Tuesday. Analysts expect a big drop in energy-industry spending to amplify the economic fallout from the coronavirus, with factories shut, streets empty and consumers unable to take advantage of low fuel prices.

Energy producers have lost hundreds of billions of dollars in market value this year, and shares fell again Tuesday. Royal Dutch Shell PLC and BP PLC lost at least 3%, as did some U.S. companies. Speculation about bankruptcies and possible mergers in the industry is driving wild stock-price swings, and possible issues with energy loans could ripple to the banking industry.

Producers are unable to shut wells fast enough, and supply cuts by the Organization of the Petroleum Exporting Countries and other nations have come too late. Traders say that the world is running out of space to store oil, driving prices below $0 a barrel for the first time on Monday.

“Traders just capitulated to the fact of the limited access to storage,” said Eelco Hoekstra, chief executive of Royal Vopak NV, a Dutch firm that runs 66 terminals for storing commodities around the world. “It’s been brutal.”

Vopak has already rented out almost all of its oil terminals, Mr. Hoekstra added.

Brent crude futures, the international benchmark for oil markets, dropped 24% to $19.33 a barrel, their lowest level in more than 18 years. The U.S. contract for delivery next month, which settled at a historic minus $37.63 a barrel Monday, rose to expire at $10.01 in thin trading Tuesday.

“Whatever oil analysts and oil traders have learned over the course of the last 50 years or 100 years was all of a sudden put in question” by Monday’s negative oil prices, said Eugen Weinberg, head of commodities research at Commerzbank. “Everyone has been shocked.”

The plunge has burned individual investors who had poured money into United States Oil Fund LP as they bet on a revival in oil prices in recent weeks. The popular exchange-traded fund fell 25% Tuesday, taking its rout this year to nearly 80%. The company that operates the ETF is reshaping it for now into what will effectively be a closed-end fund with a fixed number of shares and fewer near-dated crude futures contracts.

Oil futures, used by investors to bet on the direction of prices and by producers to protect against market swings, had performed better than the physical oil market for several weeks. Now, they are being stung by the slide in demand for actual barrels of crude.

“This is the market signaling to producers that you need to cut off more production faster because we’re drowning in oil at this point,” said Saad Rahim, chief economist at Swiss commodities trader Trafigura.

Market mechanisms that might help address the slump appear to be breaking down because of the lack of storage space.

Typically, low U.S. prices would encourage traders to buy cheap American oil and sell it at a higher price in Europe or Asia. The way Brent crude prices sank in tandem with WTI on Tuesday suggests “the world doesn’t want to take U.S. barrels,” said Vincent Elbhar, co-founder of Swiss hedge fund GZC Investment Management.

Recent moves also prompted discussions between Saudi Arabia and other members of OPEC about whether to cut production immediately. OPEC members are considering bringing forward the start date for production cuts from May 1.

“We have to face up to the reality that despite OPEC’s pledge, a lot of May cargoes have already been committed,” said Harry Tchilinguirian, head of commodities research at BNP Paribas. In effect, he said, “the cuts will only start to happen in June.”

U.S. oil companies including Chevron Corp. and ConocoPhillips have said they would reduce output. But traders say the industry isn’t moving fast enough to alleviate the selloff. This week’s price moves will be a huge wake-up call for complacent oil-company chiefs, said Edward Marshall, a commodities trader at Global Risk Management.

“If they do nothing and sit there like rabbits in the headlights waiting to be hit by a car, they’ll be hit,” he said. “I wouldn’t be surprised to see even more [capital expenditures] cuts…even more layoffs, even more jawboning by OPEC,” Mr. Marshall added. “It’s got serious now.”

Updated: 5-2-2020

Small Oil Drillers Are Turning Off Taps More Quickly Than Anticipated

From Texas and Wyoming to North Dakota, smaller companies are concluding it is better to keep oil in the ground after prices crashed.

Small U.S. oil companies are shutting off wells faster than expected, as prices fall below what it costs them to pump the crude out of the ground.

The collapse that sent U.S. benchmark prices into negative territory last week persuaded many smaller-scale, privately held drillers to shut many of their wells until the economy revs up again and demand bounces back. These drillers—in places like West Texas, New Mexico, North Dakota, Wyoming and Louisiana—collectively account for about a quarter of American production.

The pullback means that a sizable amount of U.S. oil production could stay in the ground for months, while refiners burn through a glut of crude in storage. Consequently, some observers have sharply revised U.S. forecasts for 2020 production, with faster and deeper cuts than previously expected.

Ken Waits, chief executive of Mewbourne Oil Co., one of the largest private producers in the Permian Basin of Texas in New Mexico, said many companies are receiving less for their crude than needed to cover operating costs. By next month, the Texas-based company expects to shut in more than half of the approximately 100,000 barrels a day it pumps in the region.

“What we’ve seen with the tremendous reduction in demand is just unprecedented,” Mr. Waits said. “Those prices are just not sustainable.”

Several small producers said they don’t plan on bringing wells back online until regional prices climb above $20 or $30 a barrel and stay there for a while. While U.S. prices have rebounded since April 20, they remained below $20 at $15.06 on Wednesday.

Iron Oil Operating LLC of Montana has stopped producing almost all of its 3,500 to 4,000 barrels a day in North Dakota’s Bakken Shale. In Louisiana, Velandera Energy Partners LLC said it has shut in about three-quarters of its oil output but declined to reveal the exact amount.

The motivation behind shutting in the wells is simple: Better to keep oil in the ground than lose money selling it at current prices. The bet is that prices will recover enough to cover restart costs and boost sales within a few months.

“I don’t want to see our production sold for a loss,” said Brent Allen, a managing director at Texas-based Alpar Energy LP. It has nonoperating interests in several West Texas wells that will be shut off over the next two months.

Private companies produced roughly a quarter of U.S. oil production last year, according to consulting firm RS Energy Group.

The shut-ins by smaller companies are a major reason U.S. oil production, which has recently led the world, is now projected to fall substantially in coming months.

Consulting firm Rystad Energy forecasts that U.S. output will fall from 12.8 million barrels a day in January to 10.9 million a day in June and as low as 10.3 million a day in September. In early April, before oil fell below $0 a barrel, the Energy Information Administration had predicted U.S. output would fall to 11.7 million barrels a day in June and about as low as 10.9 million a day in October.

The longer the shutdowns persist, the more likely that they lead to continued job reductions in the oil sector, executives said. When companies slash drilling-related spending, the oil-field services companies and contract workers that do much of the work are hit hardest.

Anschutz Exploration Corp. has shut in all of its wells in Wyoming’s Powder River Basin and let go of all the contract workers involved in their production. The Denver-based company had projected that the wells would produce the equivalent of 18,000 barrels of oil a day in April.

“We’re prepared to leave these wells shut in for an extended period,” said Joe DeDominic, the company’s president, noting it could take several months for prices to substantially recover.

While painful for companies and workers, the shut-ins could help rebalance the oil market. Production cuts of 9.7 million barrels a day by OPEC, Russia and other countries are set to begin taking effect in coming months.

“This is a slap in the face the market needed,” said Ben Luckock, co-head of oil trading at global commodities trader Trafigura Group Pte Ltd. “The market was producing too much crude oil.”

Mr. Luckock said U.S. production declines that Trafigura had originally forecast for the end of 2020 have been accelerated by six months and are now growing further.

Some larger U.S. shale drillers aren’t cutting production as steeply as their smaller peers. Pioneer Natural Resources Co. PXD -7.15% has shut down roughly 2,000 low-performing wells, nearly all of them older traditional oil wells. Their output totals only about 7,000 barrels of oil daily, or roughly 3% of the company’s daily output during the fourth quarter of last year, Chief Executive Scott Sheffield said. The company isn’t planning a wider shut-in program, he added.

“We’re 100% hedged, and we have firm transportation to the Gulf Coast. And we expect to export most of our crude,” Mr. Sheffield said.

Some smaller companies have higher production costs and don’t have the same ability to move their oil to customers. Trinidad Energy LLC plans to pump roughly 30 barrels a day, down from 225, and store oil at its field until prices rise enough to make it profitable again, said Kyle McGraw, the company’s president.

“My hope is we open the country back up and get people back to flying and driving,” Mr. McGraw said, adding that his storage tanks have enough capacity for about three months. “Is 90 days long enough?”

Updated: 5-6-2020

Oil’s ‘Relief Rally’ Stalls After Prices Double

The rally raises hopes—but not confidence—that the mounting fuel glut won’t overwhelm the world’s capacity to store oil.

Energy producers are throttling back their output, drivers are returning to the road and U.S. oil prices are roughly twice what they were a week ago, raising hopes—but not confidence—that the mounting fuel glut won’t overwhelm the world’s capacity to store oil.

Since reaching a record in mid-March, daily U.S. crude production has declined by more than a million barrels and big producers are promising to push it lower yet by shutting in old wells, waiting to bring online the newly drilled and dialing down flows where they can.

Meanwhile, demand for transportation fuels has begun to climb back from what was at least a 30-year low in early April. Executives at the largest U.S. refiner say that the worst of the historic drop in fuel demand caused by the coronavirus pandemic appears to be in the rearview mirror.

West Texas Intermediate for June delivery fell 2.3% to close at $23.99 a barrel Wednesday, its first decline after five days of gains. That is down 61% from the start of the year but a marked improvement from April, when supply and demand were so out of whack that it appeared there would be no place to store the excess and May futures contracts traded below $0 for the first time ever.

“I never thought $22 oil would be exciting,” said Diamondback Energy Inc.’s finance chief, Kaes Van’t Hof. That was early Tuesday, before the main U.S. oil price pushed higher to close at $24.56, up 99% from a week earlier. “It certainly looks better for the June month from a contract perspective than it did in May,” he said.

Goldman Sachs Group Inc. analysts call the climb a “relief rally” and said it would take much longer for West Texas Intermediate to double again. They don’t expect it to average more than $30 a barrel this quarter or next, but forecast U.S. oil to exceed $50 by the second half of 2021.

Given the glut motorists and airlines must burn through, producers will have to keep cutting production to buoy prices and prevent storage facilities from filling, they and other analysts say.

Companies such as Diamondback are doing their part. The Austin, Texas, firm, which produced about 200,000 barrels of oil a day during the first quarter, ceased bringing new wells to production in March and said it would reduce planned output by 15% this month.

“The risk of WTI prices declining further outweighs the benefit of producing as much as possible,” Chief Executive Travis Stice told investors on Tuesday.

Two of Diamondback’s rivals in the Permian Basin of West Texas said they would take even greater portions of their oil off the market.

Centennial Resources Development Inc. suspended drilling and well-completion work and plans to curtail up to 40% of its production this month. Parsley Energy Inc. has shut in hundreds of older wells that together produced more than 5,000 barrels a day and will choke back as much as 23,000 barrels a day in May. Pipeline operator Plains All American Pipeline LP said it expects roughly 1 million barrels of Permian production will be shut in this month.

“Currently the world does not need more of our product and we only get one chance to produce this precious resource for our stakeholders,” said Parsley CEO Matt Gallagher.

U.S. crude production was a record 13.1 million barrels a day in mid-March when many Americans were ordered to shelter in place to avoid spreading the deadly virus. By May 1, it was down to 11.9 million barrels as producers ranging from ConocoPhillips to scores of closely held concerns closed the spigots.

In the three weeks since April 10, when demand for transportation fuels was at multidecade lows, consumption of gasoline has risen 31% as parts of America began to reopen, according to U.S. Energy Information Administration data that approximately measure petroleum-product consumption. Jet fuel use, after rising 73% the week ended April 24, declined during the most recent week and is up 11% since April 10.

The U.S. Energy Information Administration is scheduled to release supply data for the week ended May 1 on Wednesday.

The data include approximate measures of petroleum-product consumption. Early last month, demand for gasoline and jet fuel plunged to multidecade lows.

In the two weeks since April 10, consumption of gasoline has risen 15% and jet fuel 73% as parts of America began to reopen.

There were an average of 76,833 daily flights during the week ended May 5, up 14% from April 10 though still not half as many as in February, according to flight tracker Flightradar24.

“The week of April 6 is really what we’re calling kind of the bottom of the market.” said Brian Partee, who heads refinery fuel sales for Marathon Petroleum Inc.

Since then, the Findlay, Ohio, company’s sales have increased steadily, though not enough for Marathon to restart refineries in California and New Mexico that it idled in response to the dramatic drop in demand.

Retail gasoline sales at its thousands of filling stations fell more than 50% and have recovered between 5% and 15% from their low, depending on the region, said Timothy Griffith, president of Marathon’s Speedway business.

“There’s probably a few months before we can really give a better sense for exactly how this is going to play out, but we’re definitely off the lows,” he said.

Updated: 5-7-2020

The Glut Drowning The Oil Market

Excess supply is collapsing crude prices and threatening energy producers.

The world is running out of room for its oil.

Dwindling Storage Space At The Cushing, Okla., Hub Helped Push An Oil-Futures Contract Below $0 A Barrel Recently, Analysts Say.

Lockdown measures are crippling demand, and supply isn’t falling quickly enough to keep up. Oil-storage tanks around the world are rapidly filling with crude, leaving the new production coming out of the ground with nowhere to go.

The overwhelming glut is threatening one of the world’s vital industries and could prolong the economic fallout from the coronavirus. As storage filled, one price for U.S. crude recently fell below $0 a barrel—a first in oil-market history—effectively meaning sellers would have to pay buyers to take barrels off their hands.

Even with a recent rebound as parts of the world reopen for business, oil trades at a fraction of where it started the year. U.S. crude futures closed down 1.8% at $23.55 a barrel Thursday, extending a streak of wild moves by erasing an earlier 11% rally. Most energy companies would lose money producing at these levels.

Stockpile data are incomplete or delayed, but recent figures already illustrate the crisis.

Global oil inventories fall into two main categories: commercial stockpiles and strategic reserves held for emergencies. Most investors focus on changes in commercial inventories because those are most sensitive to shifts in global supply and demand.

Producers and traders who don’t want to sell crude at today’s low prices can try to store it in hubs around the world, then sell in the future. The problem now is that demand for storage space is skyrocketing.

U.S. commercial stockpiles are rising at their quickest pace ever in government data going back to 1982. At 532.2 million barrels during the week ended May 1, inventories are soon expected to blow past a record of 535.5 million barrels set in March 2017.

The increase has been pronounced in Cushing, Okla., a key hub. Analysts said dwindling storage space in Cushing contributed to the recent drop in one futures contract below $0 a barrel. On April 20, that futures contract was close to its expiration date—meaning traders had to either sell it or accept delivery of actual barrels of oil at Cushing by the following month.

Those stuck holding the contracts likely couldn’t find available storage for oil and began paying others to take the contracts from them.

It is hard to know how much space is actually available. Logistical hurdles mean storage tanks can’t be filled to the brim, and competition for remaining space is fierce. That means much of the remaining empty room could have already been claimed for future use.

Even so, the official Energy Information Administration figures show Cushing inventories rising at a pace that would have them completely full in weeks.

As a result, crude-futures prices recently traded around their lowest levels in two decades.

Normally, when oil prices slide, consumers travel more, limiting the price drop and eventually spurring a rebound. But with much of the world practicing social distancing, fuel consumption has plummeted.

That means companies industrywide are struggling. Refiners such as Marathon Petroleum Corp.  and Valero Energy Corp.  that take in oil and turn it into petroleum products including gasoline are bringing in much less crude. The extra crude must find a home in storage.

Oil Tankers Anchored Off California On April 21 As Many Act As Floating Storage For Crude.

In addition to Cushing, other U.S. storage hubs are located in the Gulf Coast. A flood of oil from Saudi Arabia, the world’s largest exporter, is starting to arrive in the region—fallout from a March production feud between the kingdom and Russia that raised global supplies even as demand crashed.

That extra crude could make the glut in the U.S. even worse. Oil normally moves seamlessly through a network of pipelines and storage hubs across the country, but more of it will have nowhere to go.

The excess oil is forcing energy companies to curb spending and shut in productive wells. Some companies are starting to go bankrupt and lay off employees. The turmoil is erasing hundreds of billions of dollars from the sector’s market value.

There is also a large amount of oil floating at sea with nowhere to go, according to cargo tracker Kpler. Some ships have even been crowding off the California coast recently.

Oil-market analysts are also watching inventories overseas, particularly in China, the world’s largest commodity consumer. Figures from analytics company Kayrros show a rise in those stockpiles recently, too.

And with supply projected to continue exceeding demand for now, many analysts expect prices to remain volatile.

Most energy companies would lose money producing at current oil prices. Idled drilling rigs in Texas last month.

Updated: 5-11-2020

Shale-Drilling Pioneer Chesapeake Energy Warns Its Future Is In Peril

Company co-founded by late wildcatter Aubrey McClendon was struggling with debt even before recent collapse in oil prices.

Chesapeake Energy Corp. warned that it may not be able to stay in business as weak oil and natural-gas prices imperil a yearslong effort to pay down hefty debt.

The shale-drilling trailblazer said Monday that it has hired advisers to explore options including bankruptcy and raised doubt about its ability to remain a going concern as it reported a first-quarter loss of about $8.3 billion, compared with a loss of $21 million during the same period a year earlier.

The company wrote down the value of its oil and gas assets by about $8.5 billion, much of which was related to oil-rich properties in Texas, Wyoming and Louisiana.

The Oklahoma City company, co-founded in 1989 by the late wildcatter Aubrey McClendon, was once among the biggest companies in the American fracking boom. But it has been selling off pieces of itself for years to try to whittle away at substantial debt it incurred aggressively leasing land for drilling around the U.S.

More recently, the longtime natural-gas company tried to become a bigger player in oil, in part by buying Texas driller WildHorse Resource Development Corp. in a deal valued at about $4 billion, including debt, that closed little more than a year ago.

The company’s path forward has narrowed in recent months as oil demand and prices have tumbled while people hunker down to avoid the new coronavirus.

Oil and natural gas prices settled around $25 a barrel and $1.82 per million British thermal units on Friday, respectively.

Chesapeake is among dozens of U.S. shale firms facing possible bankruptcy. At a U.S. benchmark oil price of around $20 a barrel, analytics firm Rystad Energy expects some 140 U.S. oil-and-gas companies to file for bankruptcy protection this year.

Whiting Petroleum Corp., which filed for chapter 11 in April, was the first major shale driller to be done in by the oil-price crash.

Many of these companies were in a financially precarious position long before oil consumption fell off a cliff and prices tumbled with it, careening below zero in April for the first time on record. In fact, oil and gas was the most distressed U.S. sector at the end of 2019, according to S&P Global Ratings, with roughly 28% of the bond issues of junk-rated companies trading at distressed levels. That soared to about 70% as of late April.

Chesapeake’s debt totaled about $9.5 billion as of year-end, S&P Global Market Intelligence data show. Its bonds due in August traded around 5 cents on the dollar Friday.

The company included a going-concern warning in its third-quarter securities filing last year, but was able to remove the language after pursuing a distressed debt exchange.

Chesapeake’s shares were down about 8% early Monday afternoon. The company was in danger of being delisted before a reverse stock split in April.

Chesapeake and one of its largest bondholders, mutual-fund company Franklin Resources Inc., have hired law firms to prepare for a possible restructuring, The Wall Street Journal has reported.

On Friday, Chesapeake said in a securities filing that executives could earn cash retention payments in exchange for waiving their rights to this year’s equity and bonus awards, a move that often precedes bankruptcy. Those cash payments would total about $25 million, split between 21 people. Corporate governance data firm Equilar Inc. said it was unclear how much each executive would receive.

Chesapeake Chief Executive Doug Lawler would need to forfeit 2020 compensation valued at more than $2 million, Equilar said.

Updated: 5-11-2020

Wanted: Somewhere, Anywhere, To Store Lots of Cheap Oil

Storage schemes get creative, with would-be investors looking to sock it away in giant pools, caves or anywhere else.

Rhett Kenagy and a high-school pal recently came up with a plan to rent hundreds of school-bus-size metal tanks and fill them with some 270,000 barrels of oil.

The two are among the entrepreneurially minded individuals who hope to turn a buck from the crash in oil prices. With demand way down and companies running out of places to put crude, these people are floating schemes to sock it away until prices rebound wherever they can: in caves, abandoned rock mines and even giant pools.

Mr. Kenagy’s plan involved trucking in his haul from shale fields and parking the tanks on land outside of Houston and in West Texas. He says he has been able to score oil for $1.18 a barrel recently, cheaper than a gallon of gasoline in most of the U.S. In January, U.S. benchmark oil fetched more than $60 a barrel.

“There’s nowhere else to put the stuff,” says Mr. Kenagy, the 44-year-old managing director of fuel blending and storage companies. “You show up with a bucket to put it in, they’ll sell it to you.”

U.S. benchmark oil prices fell to negative $37.63 a barrel April 20, meaning that people were actually paying others substantial amounts to take oil off their hands. Prices have since rebounded to about $25. But if you hold on to your oil until later in the year, you can get more than $30 a barrel for it—the going price in futures markets.

Demand for oil storage is so fierce that water companies are expanding into crude storage, using large cylinders that resemble big aboveground swimming pools.

Cooley Group Holdings Inc., a textile-manufacturing company in Rhode Island, is churning out tens of thousands of pounds of polymer-coated fabric to line cylinders that another company, Well Water Solutions and Rentals Inc., has begun installing in West Texas. Each cylinder is about 190 feet in diameter and can hold roughly 50,000 barrels.

“You’re filling a swimming pool with crude oil and you’re going to put a cover on top,” says Dan Dwight, Cooley Group’s chief executive. “I’m not sure I want to take a dip in it.”

Billionaire pipeline magnate Kelcy Warren’s company, Energy Transfer LP, has looked to fill some of its Texas pipelines with crude this month and leave it there until prices go back up.

“Every little bit helps,” Mr. Warren says.

Then there are fuel bladders, which resemble a blowup mattress a giant might sleep on. Scott Sagalow started getting calls in early April from those seeking to stash oil in bladders made by his Florida-based company, Ready Containment LLC. The largest costs about $65,000 and can hold roughly 5,000 barrels.

The calls have come from both investors and oil producers, he says. With the International Energy Agency estimating that global crude demand is down by about a quarter due to people staying at home, oil companies face a trade-off: secure storage, any storage, or shut off wells, a costly proposition. “They’re all scrambling, deciding, hey, what’s the lesser of two evils?” Mr. Sagalow says.

Josh Young, chief investment officer of Bison Interests LLC, a Houston firm that invests in oil-and-gas companies, tried to get into the game but realized the complications. He decided instead to buy stock in tanker companies whose vessels have transformed into floating storage.

“Think about if you catch one fish and you try to sell it to the grocery store versus if you’re a licensed fisherman,” he says. “Your pricing ability changes a lot.”

Logistical issues and regulatory snags have foiled other plans. Customers were interested in parking railcars full of crude at Ironhorse Permian Basin LLC’s New Mexico rail terminal. Then they struggled to get the cars there, Ironhorse Chief Financial Officer Kevin Ramage says.

American Gilsonite Co. looked into converting abandoned Utah rock mines into holding sites for millions of barrels of crude, but scrapped the plans after regulators balked.

“The initial feedback we got was, ‘Guys, hey, from a geological perspective, this is not a good application,’ ” says Craig Mueller, the company’s chief executive.

The crush of interest has been good for Ernie Barsamian, who runs a website called The Tank Tiger that’s the Craigslist of oil storage. But some new people wanting to get in on the action mistakenly believe oil barrels are still held in actual barrels. One man asked if he could rent out his solarium to warehouse them.

“I explained that’s not exactly what we do,” Mr. Barsamian says.

Crude used to be transported in whiskey barrels in the 1860s, soon after oil was discovered in the U.S., says Paul Horsnell, who leads commodities research for the bank Standard Chartered PLC. But the barrels leaked and jammed creeks as they traveled downstream to be loaded onto trains, and people quickly abandoned the practice, he says. Oil today is typically stored in metal tanks the size of a multistory building, or thousands of feet underground in salt caverns.

Earlier this year, Converge Midstream LLC’s caverns in Houston-area salt formations were less than 20% full of crude. Everything changed in early March, when Saudi Arabia stoked an oil-price war with Russia, says Converge CEO Dana Grams.

As of early May, Converge’s storage capacity of more than six million barrels was nearly full.

Mr. Grams compares the pre-oil glut version of his firm to the dorky kid in high school everyone ignored until he suddenly started looking kind of hot.

“They go away for a summer and come back reborn and everybody wants to be their friend,” he says.

The storage schemes have brought back memories for Tom Loughrey, the president of an oil-and-gas consulting firm. His dad decided to stock up on heating oil around 1986, after crude prices fell by more than half. His dad buried tanks holding several years’ worth in the front yard of the family’s Middletown, N.J., home.

Each fall, Mr. Loughrey’s dad would decide whether the family was going to buy more heating oil or use their “home reserve.”

“We had these hand pumps and we would rig up hoses between the tanks and we would shift it around every year,” Mr. Loughrey says. “I thought it was extremely strange at that point. Who wants to help your dad do this crazy stuff?”

Now 43, Mr. Loughrey says it may be time to get creative himself: “I, too, would like to put some oil somewhere for 10 years or so.”

Updated: 5-21-2020

Harold Hamm, Fracking Pioneer, Faces a Career Reckoning

Founder of oil giant Continental Resources revolutionized the industry and helped usher in the U.S. energy boom. Now he’s slashing production and ripping up delivery contracts to try to survive the price collapse from coronavirus shutdowns.

Harold Hamm, the wildcatter who helped usher in the American fracking boom, has weathered his share of oil busts. None of them matched this one.

The 13th child of Oklahoma sharecroppers, Mr. Hamm rose from the bottom of the oil business to become a self-made billionaire. He is one of the pioneering prospectors who turned the U.S. into the world’s leading oil producer by using hydraulic fracturing and horizontal drilling techniques to unlock huge volumes from rock formations.

As an oil rout fueled by the coronavirus pandemic forces energy companies to take drastic measures, Mr. Hamm has more to lose than nearly anyone. He owns nearly 80% of the company he founded, Continental Resources Inc., an unusually large stake among publicly traded oil-and-gas companies.

As its shares have plunged, so has his net worth. Mr. Hamm lost more than $3 billion in just a few days in March after Saudi Arabia and Russia triggered oil’s crash by flooding the world with crude in a poorly timed war for market share.

Still full of fire at age 74, the man who once called OPEC a “toothless tiger” didn’t take the losses lying down. Mr. Hamm made numerous calls to President Trump, urging him to take a more forceful role in persuading Saudi Arabia and Russia to end their standoff, according to people familiar with the matter.

When Mr. Trump helped broker a 23-nation pact to cut output on April 12, Mr. Hamm took a victory lap, calling other executives to take credit for getting the president involved. Days earlier, he sent an email to Continental’s workers suggesting the worst was over.

“Their goal was to put us out of business. They will fail!” he wrote. “As long as the President continues to put American Energy First, we will overcome this.”

The oil plunge didn’t pass—demand evaporated as people stayed home, stopped driving to work and canceled travel plans.

On April 20, for the first time in history, U.S. oil prices went negative, meaning that some people were paying others to take oil off their hands. Oil prices have partially recovered but still hover around levels many operators need to merely break even. On Wednesday, U.S. crude climbed above $33 a barrel, its highest level since March 10.

The crisis comes after a tough period personally for Mr. Hamm, following a recent cancer scare. Mr. Hamm had a malignant polyp removed from his colon in December 2017, according to Continental General Counsel Eric Eissenstat.

The company never disclosed he had been dealing with health issues. A company spokeswoman called his health “excellent.”

Mr. Hamm stepped down in December 2019 as Continental’s chief executive but continues to serve as its executive chairman. That month, Mr. Hamm said the time was right for a leadership change, but that he would remain closely involved in running the company.

Continental otherwise declined to comment and didn’t respond to a detailed list of questions. Mr. Hamm declined an interview request.

The company’s shares have partially recovered recently, closing at $13.88 on Wednesday, about double their low point during the Saudi-Russia market war. Shares remain down nearly 60% since the start of the year.

To cut expenses and save his oil for better prices, Mr. Hamm has slammed the brakes on drilling, shut off existing wells and taken other extreme steps.

Continental told some customers that it will no longer deliver crude to their refineries as called for under contract, citing a “force majeure,” or unforeseeable event, due to the coronavirus pandemic, limited storage and demand, and other factors that led to the historic price crash, according to an April 21 letter.

Continental is also substantially curtailing its production. The company said it would cut about 70% of its daily output measured by barrels of oil in May, compared with about 3% to 26% cuts by its large rivals.

“It’s pretty stunning,” said Lynn Helms, director of North Dakota’s Department of Mineral Resources, adding that Continental is shutting off far more of its output than most other operators in the Bakken Shale oil field, one of America’s biggest shale plays.

The American Fuels & Petroleum Manufacturers have called the refusal to honor its contracts to deliver oil “putting a boot to the throat of U.S. refiners,” calling it the “height of hypocrisy” for Mr. Hamm to renege on the deal while lobbying for restrictions on imports of foreign crude.

Mr. Hamm has continued to draw on a close relationship with Mr. Trump, who said he “learned more about energy from Harold than anybody else” in a video address in February. Mr. Hamm was the president’s energy adviser in 2016, and has cultivated influence over decades with members of Congress.

He has pushed for tariffs on overseas oil, as well as investigations into possible market manipulation, without saying by whom, as a cause of the April 20 price crash, and a probe into whether Saudi Arabia is dumping crude into the global market.

Mr. Hamm, once a Democrat, has also advised Mr. Trump to quickly reopen the U.S. economy.

His lobbying since the pandemic—which has included calls for mandatory production cuts in North Dakota and Oklahoma, where Continental operates, and Texas, where it doesn’t—has so far been unsuccessful, and has proved divisive. Larger rivals including Exxon Mobil Corp. and Chevron Corp. have opposed moves by the government to cap production.

Those who know Mr. Hamm well say he has always been a maverick more aligned with smaller, independent oilmen than larger players.

Mr. Hamm drilled for oil in the U.S. long after many believed its best deposits were mostly dried up, something he has attributed to stubbornness and patriotism. He believed a resurgent U.S. oil industry would decrease the country’s reliance on foreign oil and has eschewed investing internationally, unlike larger competitors. He has also lobbied extensively for independent producers, or those focused primarily on U.S. drilling.

“He’s clearly that voice,” said Oklahoma Sen. James Inhofe, a Republican and a close ally of Mr. Hamm’s who has supported his call for an anti-dumping investigation.

A self-taught geologist with no college degree, Mr. Hamm struck it big in North Dakota’s Bakken region, an oil field that had been discovered decades earlier but was largely overlooked. Some in the industry called it “Hamm’s folly,” thinking there wasn’t much recoverable oil left.

Using new technology, Mr. Hamm extracted huge amounts of oil and gas from rock formations previously considered too difficult to tap. The discoveries led to an oil boom that lifted North Dakota’s employment and economy, a bright spot for the U.S. following the 2008 recession.

It made him fabulously wealthy when Continental went public in 2007, just as the shale boom was beginning. By 2012, the company was one of the top 10 oil producers in the U.S. Mr. Hamm’s stake eventually topped $19 billion.

Still, he maintained a relatively frugal lifestyle. Mike Cantrell, Continental’s former head of government relations, recalled how Mr. Hamm would fly coach to Las Vegas to place modest bets on the NCAA basketball tournament with other Oklahoma oilmen, and drive the rental van from the casino to the golf course.

Mr. Hamm has said he didn’t realize he was poor growing up. He fell in love with the oil field after high school, enamored with the industry’s large personalities. Described by friends as an introvert, Mr. Hamm’s reserved nature belies his intense competitiveness.

He speaks with a soft Oklahoma drawl and is known to prefer bluejeans to suits, though he sometimes wears a diamond encrusted company ring. Those who know him say he was long uncomfortable with public speaking, partly due to his lack of formal education, but in recent years has embraced a more public role.

“He wanted to build a world-class oil company and his appetite was just unending,” said Mr. Cantrell. He is no longer on speaking terms with his former boss after taking up the cause of older wells damaged by newer neighboring ones, including those drilled by Continental, in Oklahoma. Nonetheless, Mr. Cantrell said, he wouldn’t bet against Mr. Hamm’s ability to survive an oil bust.

After a plunge in oil prices to nearly $10 a barrel in 1999, Continental was losing so much money it had to fire much of its oil exploration staff and cut pay for those remaining. Mr. Hamm formed a coalition of smaller drillers and filed dumping allegations against Saudi Arabia, Mexico, Venezuela and Iraq.

Despite pursuing the suit for years, the coalition failed to persuade the Clinton and Bush administrations to take action. But Continental held on, and Mr. Hamm had shown his willingness to take on larger competitors.

“Don’t get in a lawsuit with him unless you’ve got deep pockets and a lot of time,” Mr. Cantrell said.

Even before the coronavirus crisis, U.S. shale drillers were in trouble. Many amassed sizable debts building large shale positions in North Dakota and Texas, and were struggling to generate positive cash flow.

Continental has a wall of debt coming due in the next few years, in part because the company has issued far less stock than many of its peers, preferring to raise debt instead. That has maintained Mr. Hamm’s stake in the company but means it will need large amounts of cash.

The company, with a current market capitalization of about $5 billion, had about $4.3 billion in debt coming due through 2024 as of the end of the first quarter, more than all but one of 15 other large independent U.S. oil producers, according to FactSet.

Continental is also more exposed to price fluctuations than most. While many oil companies use complex financial instruments to hedge a portion of their production and protect themselves from falling prices, Mr. Hamm has long eschewed the practice, which can hurt companies’ profits in the event of a price surge.

Continental was completely “naked” as the current price rout took hold, unlike most large shale drillers, which had locked in prices for at least some of their 2020 production at around $50 a barrel, according to S&P Global Market Intelligence.

Mr. Hamm’s company is geographically constrained compared with rivals in Texas. Much of its production comes from North Dakota, more than 1,000 miles from the main market for most U.S. oil, the Gulf Coast’s petrochemical mega-complex. That means extra costs to move the oil to market along with other factors, forcing Continental to sell much of its oil for a discount.

Bakken producers on average need crude prices of $28 a barrel to cover operating expenses for existing wells, and $51 a barrel to profitably drill a new well, according to a March survey of oil executives by the Federal Reserve Bank of Dallas.

“It’s clearly not a happy place to be,” said Sandy Fielden, an analyst at Morningstar Inc., adding that Continental’s decision not to hedge against the risk of falling oil prices was a notable “unforced error,” as other producers are now counting on hedges to survive.

Mr. Hamm will fight for his interests no matter the cost, said Mickey Thompson, an Oklahoma oilman and decadeslong friend of Mr. Hamm’s who worked with him on state policies. The two irreconcilably split after Mr. Thompson supported a successful bid to increase taxes on Oklahoma oil and gas production and said Mr. Hamm was denying any connection between fracking and earthquakes.

Despite their disagreements, Mr. Thompson, who once wrote a book about Continental at Mr. Hamm’s behest, said it was the only shale company he would invest in right now, because Mr. Hamm will find a way to persevere.

“Harold has never been afraid to do whatever he thought it took,” Mr. Thompson said.

Updated: 5-24-2020

Coronavirus Threatens To Hobble The U.S. Shale-Oil Boom For Years

Drillers that survive pandemic are likely to be leaner and less inclined to invest freely in growth.

American shale drillers helped turn the U.S. into the world’s top oil producer, topping 13 million barrels a day earlier this year. It likely will be years—if ever—before they reach such heights again.

That is the growing view among top oil and natural-gas executives and experts, who say the coronavirus pandemic is going to thin the ranks of shale companies and leave survivors that are smaller, leaner and less able to pursue growth at any cost.

Shale companies led a renaissance of American oil production, helping to more than double output over the past decade. That propelled the U.S. past Saudi Arabia and Russia and made the country an important competitor in the geopolitics of energy and global markets.

But before the new coronavirus sapped global demand for crude, causing shale-drilling companies to shut off wells en masse to avoid losing money, many were struggling to turn a profit, and investors had soured on the sector, restricting companies’ access to capital.

While oil prices have rebounded in recent days and are above $33 a barrel, U.S. output is still poised to fall because companies aren’t drilling enough wells to make up for production declines from existing wells. Shale wells produce a lot of oil and gas early on, but quickly lose steam. Without investing in new wells, many companies’ output would decline by 30% to 50% in just a year, research firm Wood Mackenzie says.

Shale-oil companies have sharply reduced their drilling budgets for the year, with the top 15 by market capitalization slashing spending by an average of 48%, a Wall Street Journal review of company disclosures found. Forty-six independent U.S. producers planned a combined $38 billion in capital investments this year, the lowest dollar amount since 2004, according to Cowen.

“We believe there’s going to be significantly less capital invested in growth in the U.S.,” said Bill Thomas, chief executive officer of leading shale driller EOG Resources Inc., EOG -0.08% which has reduced its capital budget 46% for the year. It is unlikely U.S. production will reach previrus levels in the next several years, he added.

Since mid-March, operators have idled almost two-thirds of the U.S. rigs that had been drilling for oil, bringing the nation’s oil-rig count to the lowest since July 2009, according to services firm Baker Hughes Co. That all but ensures U.S. production is going to fall, even if companies decide to restart existing wells sooner than expected.

U.S. oil output fell to 11.5 million barrels a day in mid-May, according to the Energy Department, after companies turned off wells. Some estimate production has already sunk lower.

Pipeline giant Plains All American Pipeline LP estimated producers shut off nearly one million barrels a day of production this month in the Permian Basin of West Texas and New Mexico. In North Dakota’s Bakken Shale, producers cut about 500,000 barrels a day from February to mid-May, state regulators said.

The question is whether the companies ever return to their production highs. The Energy Department now expects U.S. oil production to slide to about 10.8 million barrels a day early next year, down from its January forecast of 13.5 million daily by that time.

Daniel Yergin, vice chairman of IHS Markit, expects U.S. oil output to bottom around nine million barrels a day next summer, before eventually returning to about 11 million barrels a day.

“February was peak shale,” Mr. Yergin said.

He and others say that, even when the industry recovers, the pace of growth is unlikely to match the frenetic boom of recent years, largely because the industry’s relationship with Wall Street has deteriorated after years of poor returns.

Large public U.S. producers poured a total of $1.18 trillion into drilling and pumping oil over the past decade, largely in shale plays. But they came up well short of making their money back, collectively bringing in $819 billion in cash from their oil operations, according to Evercore ISI.

That contributed to investor disillusionment with the industry. Last year, U.S. producers raised about $23 billion in debt and equity financing, less than half of the roughly $57 billion they received in 2016, when the industry was emerging from its most recent oil-price downturn, according to Dealogic.

Some sizable U.S. drillers, including Whiting Petroleum Corp. and Ultra Petroleum Corp., have filed for bankruptcy, while Oasis Petroleum Inc. and shale-drilling trailblazer Chesapeake Energy Corp. have warned they might not be able to stay in business. Fitch Ratings Inc. said the default rate among high-yield U.S. exploration and production companies could reach 25% in 2020, the highest since March 2017.

The recent rebound in oil prices alleviates some pressure on drillers, but isn’t enough for most new wells to be profitable.

“They were in trouble in a $50 oil environment,” said Lance Taylor, president and CEO of private oil producer Steward Energy II. “Thirty dollars doesn’t fix anything.”

Investors are less inclined to recapitalize companies for growth, preferring they return cash to shareholders, said activist investor Ben Dell, a managing partner at Kimmeridge Energy Management Co.

Many that can’t raise equity will use their cash flows to repair balance sheets, leaving only a handful of companies able to grow, said Scott Sheffield, chief executive of Pioneer Natural Resources Co., which has cut its annual capital budget 55%. Even in a recovery, Mr. Sheffield said his company wouldn’t boost production growth but instead would return more money to shareholders.

Amy Myers Jaffe, a senior fellow for energy at the Council on Foreign Relations, said disruptions in oil investment and output elsewhere in the world could create an opening for shale producers to resume their production peaks.

“The crux of the matter is that it’s going to be difficult to restore vertical production in a lot of places in the world, but the shale will be easier to restore, and that gives it an edge,” Ms. Jaffe said.

Either way, shale companies that emerge from this downturn are likely to act differently than the growth-obsessed frackers of recent years.

“It is going to accelerate what was happening and what investors were demanding, which is shifting from a grow-it-and-flip-it model to something more sustainable,” said Matt Adams, a portfolio manager for Franklin Templeton, which has about $600 billion in assets under management. “We’ll have a smaller, more rationalized sector.”

Updated: 6-7-2020

U.S. Shale Companies Are Turning the Oil Taps Back On

As oil approaches $40 a barrel, companies are bringing wells back online, even as the market continues to recover from the demand drop caused by the coronavirus.

American oil producers are reopening the spigots, complicating the crude market’s recovery.

Scores of shale drilling companies turned off wells to reduce output when U.S. oil prices fell to negative territory in late April, after millions world-wide stopped driving and flying due to the new coronavirus, causing a steep drop in global demand.

Now that more of the world is reopening and prices are rebounding to nearly $40 a barrel, companies including Parsley Energy Inc. and WPX Energy Inc. are starting to turn some of those wells back on, even as they continue to put off most new drilling.

The increased volumes remain far below peak levels before the pandemic, when the U.S. was pumping more than 13 million barrels a day of crude, the most in the world. But the oil market remains fragile, and many of the world’s other top producers are still voluntarily curtailing their output to help rebalance supply and demand.

The Organization of the Petroleum Exporting Countries and its allies, which agreed in April to limit production by 9.7 million barrels a day through June, struck another deal Saturday to extend cuts another month.

The extension aims to reduce output by 9.6 million barrels a day, as Mexico isn’t going to continue its production curbs. Libya, which is exempt from the quotas, also said over the weekend that it is restarting some 300,000 barrels a day of production, another challenge for global rebalancing.

OPEC delegates were briefed on the likelihood that U.S. producers would turn the taps back on last week but also discussed forecasts that American production would likely decline later in the year before agreeing to extend output cuts.

While turning existing wells back on is likely to temporarily boost U.S. production this summer, American oil output is still widely expected to drop in 2020. That is because shale wells lose steam quickly, and companies have sharply cut back on the number of new wells they are drilling.

The decline in new oil-drilling activity is likely to remain a drag on employment and the national economy. Analytics firm IHS Markit thinks the country will be generating around 10 million barrels a day by year-end, down nearly a quarter from the peak.

Global oil demand has recovered from an April trough, but the International Energy Agency estimates that this month it will still be about 86 million barrels a day, or roughly 13% below last year’s levels.

Oil prices have staged a remarkable recovery from April 20, when futures plunged to negative $37.63 a barrel as sellers effectively paid buyers to take contracts off their hands amid a growing shortage of oil storage.

In May, as stay-at-home orders eased, drivers returned to the road and American energy producers curtailed output, West Texas Intermediate futures posted their biggest monthly increase on record in both dollar terms and percentage gain. Crude futures climbed another 11% last week to end Friday at $39.55 a barrel.

“We’re seeing production coming back in pretty much all of the basins,” said Kelcy Warren, chief executive of pipeline giant Energy Transfer LP. “It’s been a steady recovery since the first week of May.”

The amount of oil traversing Energy Transfer’s systems fell about 20% from March to May, but the company said it is on track to regain about half of those losses this month.

American companies that can get their oil onto boats and into the global market can sell it for more than the U.S. price. Brent crude, the international benchmark, closed Friday at $42.30.

Current prices remain below the levels many companies need to drill new wells profitably. But the bounceback is sufficient for many to start up existing wells. The average price required to cover operating expenses on existing wells ranges from $23 a barrel to $36 a barrel in the U.S., depending on the region, according to a recent Federal Reserve Bank of Dallas survey.

EOG Resources Inc., one of the largest U.S. oil producers, has a plan to ramp its output back up in the third quarter.

“In the mid-$30s, some of the existing shut-in production will be coming back on. There’s no doubt about that,” Kenneth Boedeker, EOG’s exploration and production chief, told investors last week.

Rivals aren’t waiting. Parsley Energy told investors last week that it is already restoring a “vast majority” of the roughly 26,000 barrels a day of production that it choked back last month from its Permian Basin fields in West Texas.

WPX, which drills in the Permian as well as in North Dakota, said in a securities filing Wednesday that it is restoring the 45,000 barrels a day that it took off the market last month.

Concho Resources Inc., another Permian producer, pinched its output by some 5,000 to 10,000 barrels a day during the lockdown.

“As prices have improved, we are working to bring that production back online,” Brenda Schroer, the Midland, Texas, company’s finance chief, told an online gathering of investors.

Some operators have said in recent weeks that they planned to turn wells off for only a portion of the month rather than shutting them down entirely, said Mark Houser, chief executive of University Lands. The organization manages oil and gas leases across 2.1 million acres in West Texas for a state endowment, with the royalty payments supporting education.

“It’s a mixed bag,” Mr. Houser said.

U.S. crude production during the final week of May averaged 11.2 million barrels a day, down from a record 13.1 million in mid-March, according to the U.S. Energy Information Administration. Some estimate that output has fallen even lower.

Roughly 1.75 million barrels a day worth of production losses this spring were attributable to turning off existing wells, according to IHS Markit. The analytics firm expects most of that output to be restored by September.

But without new drilling, U.S. onshore production would decline by more than a third in a year, far more quickly than in most other places in the world, IHS Vice President Raoul LeBlanc said.

“If you stop feeding the beast, it declines incredibly quickly,” Mr. LeBlanc said.

The number of drilling rigs in the U.S. has dropped by more than 70% in the past year, to 284, according to oil-field services company Baker Hughes Co.

Mr. Warren, the pipeline chief, said the loss of rigs is worrisome, longer-term. “You pull all those rigs out, it’s not overnight like a shut-in that you can just turn it back on,” he said. “We’re concerned about declines.”

Updated: 6-8-2020

BP To Cut 14% Of Global Workforce As Drop In Oil Price Bites

The British energy giant plans to cut almost 10,000 mostly office-based jobs as the coronavirus pandemic hits demand.

BP PLC is cutting thousands of jobs, accelerating existing plans to reshape the company after the coronavirus pandemic’s crushing impact on oil prices.

The move is one of the first and most drastic from the oil industry, which is expected to shed staff after crude prices hit their lowest level in decades in April, amid pandemic-driven stay-at-home policies that parked vehicles and curbed economic activity.

BP plans to cut nearly 10,000 jobs, or 14% of its workforce, and freeze pay increases for senior level managers as it seeks to strengthen its finances, the company said Monday.

The job cuts come as newly appointed Chief Executive Bernard Looney responds to the pandemic’s devastating effect on oil demand and coincides with his attempts to reshape the U.K.-based oil giant for a low-carbon future.

Mr. Looney, who took the helm in February, had been crafting a yet-to-be revealed reorganization plan that has now been “accelerated and amplified” by the need to respond to market conditions and reduce costs, BP said.

“It was always part of the plan to make BP a leaner, faster-moving and lower carbon company,” Mr. Looney wrote in an email to employees. “Then the Covid-19 pandemic took hold…The oil price has plunged well below the level we need to turn a profit. We are spending much, much more than we make—I am talking millions of dollars, every day.”

BP, with a current workforce of around 70,000 people, said the cuts will help to drive down its operating costs by $2.5 billion by the end of 2021. The cost-cutting plan might have to go even further, Mr. Looney said in the email.

The move follows Chevron Corp.’s plans to reduce its 44,679 workforce by as much as 15%. “Most of the workforce reductions will take place this year,” said a spokeswoman for Chevron.

Royal Dutch Shell PLC said in April that it will look at resizing parts of its organization, ideally through voluntary redundancies.

Schlumberger Ltd.,the world’s largest oil-field-services company by revenue, said it cut 1,500 jobs in North America in the first quarter. Last month, its rival Halliburton Co. said it cut about 1,000 jobs at its Houston headquarters.

“I don’t think there’s ever been an oil-price downturn without a significant job reduction, and therefore we should expect more of it across other companies,” said Bernstein analyst Oswald Clint.

For BP in particular, job cuts were inevitable, given the restructuring announced in February and its cost-cutting plans, Mr. Clint added.

The oil industry’s history of boom and bust cycles are often reflected in staffing levels, but the pandemic has led to even more drastic measures from some, with companies including Shell and Equinor AS A cutting their dividends. BP said in April that it was maintaining its dividend, but Mr. Looney said it wasn’t yet clear whether the pandemic could cause permanent damage to oil demand.

“The pandemic I believe only adds to the challenge of oil in the future,” he said on the April earnings call.

The major oil company said it is aiming to bring down its capital expenditure by 25% in the year, a reduction of around $3 billion.

The cuts will introduce a flatter organizational structure, Mr. Looney said, and will mostly come from office-based roles. The majority of employees affected are expected to leave by the end of 2020.

The revised structure is expected to significantly affect senior-level management. BP said it expects the number of group leaders—the top 400 roles in the company—to be reduced by one-third.

BP is due to announce its revised strategy at a three-day event starting on Sept. 14.

Updated: 6-15-2020

Banks Cut Shale Drillers’ Lifelines as Losses Mount

Lenders are pulling back on reserve-backed loans as the shale industry faces a liquidity crunch.

Banks are slashing credit lines to shale drillers, as an oil-price crash and wells that have failed to produce as much as predicted force a painful reassessment of companies’ assets.

The cuts vary from company to company, but Moody’s Corp. and JP Morgan Chase & Co. forecast a total reduction of as much as 30% to the asset-backed loans, or tens of billions of dollars. At current prices, that will be enough to tip some weaker players into bankruptcy as capital for the beleaguered industry dries up, say bankers, lawyers and energy executives.

“It’s an unavoidable reckoning,” said Todd Dittmann, head of energy at alternative investment manager Angelo Gordon & Co., which manages about $33 billion. “A decade of bubbling public and private debt and equity capital delayed this day, but no more.”

The loans aren’t large enough to pose a systemic risk to banks, whose exposure to U.S. energy companies totals around $650 billion, or about 3.5% of U.S. bank assets, according to JPMorgan Chase. But many banks could suffer sizable losses from souring shale loans and are trying to sell off their portfolios to reduce exposure, people familiar with the matter say.

Banks regularly reconsider reserve-backed loans, part of a normal review that takes place every spring and fall, but industry veterans say the current cuts are among the most severe they can recall.

Some are concerned they could signal a permanent contraction in oil-and-gas lending, as financial institutions, already facing pressure from activists and governments to pull back from fossil fuels, retreat from a sector that has delivered underwhelming profits for most of the past decade.

“It’s a different order of magnitude,” said Buddy Clark, co-chair of the energy practice at law firm Haynes and Boone LP. “Historically, you don’t have reductions of borrowing bases across the board. This is different than any other cycle we’ve seen.”

So far, more than two dozen publicly traded shale producers have had their borrowing bases cut, according to regulatory filings and other documents.

Centennial Resource Development Inc. had its revolving loan cut from $1.2 billion to $700 million in May, days after U.S. oil prices fell into negative territory. Later that month, Moody’s downgraded the company’s credit outlook, saying its risk of default had increased, citing the borrowing base cut.

Oasis Petroleum Inc. had its borrowing base cut from $1.3 billion to $625 million in April and agreed to subsequent cuts that will lower it to $600 million. Antero Resources Corp. ’s base was cut from $4.5 billion to $2.85 billion in March.

The companies didn’t respond to requests for comment.

During the last oil-market downturn in 2015 and 2016, banks came out largely unscathed as producers sold off their assets or handed control over to bondholders. Bank loans, which had priority over high-yield bonds and other corporate debts, were largely repaid in full.

This time around, some bank lenders are finding out their collateral in the form of oil and gas assets isn’t worth enough to cover their debts as oil prices have decreased.

“That is a very material development in this sector,” with potentially long-lasting impacts on how banks lend into the oil industry, said Kevin Cofsky, a partner at financial adviser Perella Weinberg Partners LP.

Banks are also discovering that estimates they relied on for how much oil borrowers’ wells would produce are proving overly optimistic.

Templar Energy LLC, a private equity-backed producer that filed for bankruptcy June 1 after having its borrowing base cut last year, has said it expects lenders to recover at most 21 cents on the dollar. Alta Mesa Resources Inc., a Houston-based shale driller that sold its assets out of bankruptcy in April, expects its bank lenders will get roughly 51.3 cents on the dollar on $316.5 million they are owed, according to court papers.

Lenders are increasing interest rates and tightening loan covenants on shale drillers, say people briefed on the changes, including provisions meant to stop companies from drawing their revolving loan facilities in full and stockpiling the cash. Some bankers expect that lenders will also tighten limits on borrowers’ leverage.

The current talks with shale companies have proved so thorny that the banks’ traditional spring redeterminations still aren’t complete, bankers and lawyers involved say. Many expect the fall reviews to be even worse as drillers’ revenues decline due to decreased production.

For some shale companies, the revolving loans are one of their few remaining sources of cash. Even before the coronavirus sapped global oil demand, equity and credit investors had fled the industry after years of poor returns, leaving drillers with few options for inexpensive financing.

That financial crunch has only worsened this year, as scores of companies were forced to sharply curtail new drilling and turn off existing wells due to a collapse in prices, which is going to reduce their future production and cash flow.

Drillers whose debt isn’t considered investment grade are most at risk of bankruptcy. Primarily small- and medium-size shale producers, those companies make up about one-quarter of U.S. oil production.

If U.S. oil prices average about $30 this year, around 73 oil and gas producers in the U.S. may have to file for bankruptcy protection, with 170 more following in 2021, data analytics firm Rystad Energy estimates.

While the current bust isn’t expected to cause the type of pain lenders saw in the 1980s, when a crash helped trigger the savings-and-loan crisis, some banks are seeking to get out of reserve-backed loans entirely. At its peak, around 60 banks extended reserve-backed loans, according to one lender, who said the number is closer to 30 now.

Regional lenders Huntington Bancshares Inc. and Texas Capital Bancshares Inc. are actively marketing portfolios of such loans to hedge funds, private-equity firms and others, say people familiar with the matter, while Capital One Financial Corp. has had early conversations with prospective buyers.

The banks didn’t respond to requests for comment.

Updated: 6-28-2020

Fracking Trailblazer Chesapeake Energy Files for Bankruptcy

Oklahoma City-based company was once the second-largest U.S. gas producer.

Chesapeake Energy Corp. said Sunday that it had filed for bankruptcy protection as an oil- and gas-price rout stoked by the coronavirus pandemic proved to be the final blow for a shale-drilling pioneer long hamstrung by debt.

Co-founded in 1989 by the late wildcatter Aubrey McClendon, Chesapeake was early to recognize that horizontal drilling and hydraulic fracturing could unlock vast troves of natural gas, a trend that led to a rebirth of American fossil-fuel output and eventually made the U.S. the top oil producer in the world.

By the end of 2008, the Oklahoma City-based company had drilling rights to nearly 15 million acres, according to a securities filing, an empire roughly the size of West Virginia. That vast footprint once helped Chesapeake earn the title of second-largest U.S. gas producer.

But Chesapeake’s breakneck growth left it highly leveraged, and it was far slower than many of its peers to pivot to tapping shale formations for oil, which turned out to be much more lucrative than gas. The result was a painful fall in recent years as Chesapeake shrank, selling assets to pare debt before winding up in bankruptcy court.

“They were at the forefront, and they were the most aggressive. But because of how aggressive they were, it left them unable to pivot to what ended up being the real moneymaker,” said Chris Duncan, a Brandes Investment Partners director with a say in mutual funds that own Chesapeake debt.

The company, which filed for chapter 11 protection with more than three dozen affiliated companies, listed assets of $16.2 billion and liabilities of $11.8 billion in its petition with the U.S. Bankruptcy Court in Houston.

Chesapeake reached a restructuring agreement with many of its lenders that is intended to guide the bankruptcy process and seeks to eliminate some $7 billion in debt.

Chesapeake is one of many debt-laden U.S. oil and gas producers now facing a reckoning as a coronavirus-induced economic slowdown saps demand for fossil fuels.

Wall Street aided U.S. shale companies after the oil-price downturn of about five years ago, helping many companies stay afloat. But capital infusions are harder to come by after years of poor financial performance. U.S. producers raised about $23 billion in debt and equity financing last year, less than half of the roughly $57 billion they received in 2016, according to Dealogic.

With less access to external capital, dozens of smaller shale players are likely facing bankruptcy in the coming months. U.S. shale, like so many oil and gas discoveries before it, is poised to become the province of bigger, better-capitalized companies.

“If they didn’t go into this with a strong balance sheet or at least a strong line of credit, I think they will not survive,” said Archie Dunham, a former chairman of Chesapeake’s board, referring to the industry broadly. “Hopefully what has happened in the industry will teach the next generation of leaders and managers and equity holders that debt is something that you avoid to the extent that you can.”

Mr. McClendon spent most of his early days in the industry as a landman, or specialist tasked with leasing land for oil and gas exploration. Under his leadership, Chesapeake was incessant in scooping up promising drilling prospects.

“It was a race in those days to amass the biggest lease portfolio that you could. He wanted to be Exxon, ” said Harrison Williams, who advised on acreage sales to Chesapeake in the early 2000s. “There just wasn’t enough money on God’s green earth to drill it all.”

Chesapeake became one of the first stars of the fracking boom. Mr. McClendon was a charismatic pitchman, talking up the promise of American natural gas to Wall Street investors and politicians.

The company’s success allowed Mr. McClendon to champion the transformation of Oklahoma’s state capital into a more modern metropolis. He was part of a group that bought the Seattle SuperSonics NBA basketball team in 2006 and later moved it to Oklahoma City. The team, now known as the Oklahoma City Thunder, plays in the Chesapeake Energy Arena. He also indulged in his passion for fine wine, building a large collection, among many side pursuits.

But Mr. McClendon’s lavish spending eventually proved troublesome for Chesapeake. In 2008, he had to sell 94% of his stake in the company, or tens of millions of shares, to satisfy a margin call. Later, Mr. McClendon’s personal financial dealings, including his use of loans to participate in a company perk that allowed him a stake in every Chesapeake well, drew shareholder ire. Investors, including Carl Icahn, ousted him in 2013.

Three years later, Mr. McClendon died in a car crash at age 56, a day after being indicted by a federal grand jury on accusations of conspiring to rig the price of oil and gas leases. Mr. McClendon denied the charge.

By the time Doug Lawler took the helm of Chesapeake in 2013, the company was weighed down by some $13 billion in debt. Mr. Lawler has spent the better part of his tenure selling off pieces of the vast empire Mr. McClendon amassed to pay off those obligations. Year by year, he parted with assets from Oklahoma to Louisiana and a northeast drilling region that Mr. McClendon once called the “biggest thing to hit Ohio since the plow.”

Mr. Lawler deviated from that playbook in 2018, when he struck a deal valued at about $4 billion, including debt, to buy Texas driller WildHorse Resource Development Corp., part of an effort to transform Chesapeake into more of an oil producer.

But the pivot to oil, years after rivals such as EOG Resources Inc. took such a course, proved too late.

Chesapeake’s debt still totaled about $9.6 billion as of the first quarter, S&P Global Market Intelligence data show, even as its daily output of about 2.9 billion cubic feet of natural gas and oil was down roughly a third from the company’s peak and its footprint of land leased for drilling was less than a quarter of what it once was.

Under mounting strain this spring as low oil and gas prices rocked the industry, Chesapeake completed a reverse stock split in April and warned May 11 that it might not be able to stay in business, its second such warning in recent months. The company reported a first-quarter loss of more than $8 billion, led by a write-down of oil-rich properties in places including Texas and Wyoming.

Twilight Years

Chesapeake shareholders have seen returns dwindle for years as the company struggled to pay off debt.

Chesapeake also offered 21 high-ranking employees cash-retention payments totaling about $25 million in exchange for waiving equity and bonus awards, a move that commonly precedes bankruptcy. Corporate-governance data company Equilar Inc. said it was unclear how much each executive would receive. Mr. Lawler’s realized pay through the end of last year totaled more than $48 million, Equilar said.

By mid-June, Chesapeake’s market capitalization was less than $200 million, FactSet data show, down from roughly $38 billion at its 2008 peak.

Updated: 7-4-2020

‘So Unstable and So Volatile’: Oil Crash Crushes Individual Investors, Prompts Trading Overhaul

After ordinary people racked up steep losses in an April collapse, the products that drew many into amateur commodities trading are getting revamped.

For decades, regular people didn’t trade commodities. But electronic trading and new investment products prompted amateur investors to start buying and selling oil.

When prices crashed in April, that foray turned into a disaster, spreading billions of dollars in losses to ordinary people. Many of them then missed out as oil surged in May and June, posting its best quarter in 30 years.

Now mutual-fund companies are revamping their products to prevent future collapses. Traders are reprogramming computers for a world in which oil can have a negative price. And banks and brokerages are facing pressure, resulting in settlements to cover losses and a class-action lawsuit filed last month against the largest oil exchange-traded fund.

As individuals watched their money evaporate, some market professionals thrived. They understood not just commodities but also the vulnerabilities in the products amateurs were trading.

Cho Byung-jae got burned in this new trading world. A 22-year-old South Korean living in a city south of Seoul, he bought crude futures at 30 cents a barrel back in April. He then watched in horror as prices kept falling. Just after 3 a.m. local time, oil fell below $0 for the first time ever—meaning he would have to pay to get rid of his holdings.

All the while, Mr. Cho’s trading platform still showed positive prices. As he tried to sell, the platform froze. When the dust cleared, he faced losses up to $56,000.

“The prices…were going haywire,” Mr. Cho said. “There was something very wrong.”

At that very moment, customers around the world using brokerages including E*Trade Financial Corp., TD Ameritrade Holding Corp. and Interactive Brokers LLC also were unable to trade at negative prices.

These brokerages had spent years making oil products easy to trade and giving individual investors access to futures contracts like those Mr. Cho bought. Futures contracts are promises to deliver a commodity at certain times, allowing investors to speculate on price moves and producers to protect against large swings. When a regular U.S. crude futures contract expires, the holder must either sell it or take delivery of barrels of oil the following month.

Many brokerages also offer futures that are settled with cash instead of oil. Mr. Cho bought one of these “e-mini futures” that trade on CME Group Inc.’s New York Mercantile Exchange. When the contracts expire, they converge with regular U.S. crude futures.

That is what happened on April 20. Regular futures slid to minus $37.63, and e-mini futures followed, trapping traders who couldn’t trade at negative prices.

What do you think the April crash means for the future of fossil fuels? Join the conversation below.

A similar contract on the Intercontinental Exchange caused hefty losses. A chunk came from customers of Interactive Brokers, which has taken more than $100 million in losses covering for traders who held cash-settled contracts, according to billionaire founder and chairman Thomas Peterffy.

“Things like this should not happen,” said Mr. Peterffy, who wants exchanges and regulators to look into similar contracts and products tied to oil futures. An ICE spokesman declined to comment. Interactive Brokers has updated its software to account for negative prices.

Another source of pain: ETFs like the United States Oil Fund. These funds have surged in popularity, helping ordinary people enter the market while allowing sophisticated traders to wager on commodities more easily. They might have made things too easy, some analysts say.

“It’s so unstable and so volatile right now,” said Sean Douglas, a 36-year-old in Raleigh, N.C., who has about $1,500 invested in the U.S. Oil Fund. The fund’s price dropped toward $0 in late April before it executed a reverse share split to lift its shares.

Such funds are risky because they also trade futures contracts. Since the contracts expire every month, fund managers must sell them before expiration and buy the next month’s, in a process called rolling.

In normal times, prices one and two months into the future trade closely together, making it easy to roll holdings. But with prices collapsing this spring, large gaps emerged between near-dated futures and oil for delivery months down the road. And the U.S. Oil Fund had gotten so big in April that it needed to sell a huge number of front-month futures and buy a massive amount of the next month’s contracts.

Sharp-eyed traders profited by pushing down the contract the fund needed to sell and bidding up the futures it needed to buy. This activity swung oil prices, and anticipation of a repeat of that process spooked some traders out of holding any near-dated oil futures.

The ETF and other products had already sold their May futures, but whoever was left holding May contracts on April 20—the day before they expired—likely couldn’t find available storage, traders said. That forced them to pay others to take the contracts off their hands, pushing prices below $0.

The slide rippled around the world, affecting products including a Bank of China investment vehicle called “crude oil treasure.”

“I never thought oil prices could turn negative,” said Zhang Ye, a mechanical engineer who was informed the following morning in local time that he had lost his roughly $28,150 investment through the product and owed the bank another $44,925.

Bank of China had suspended trading on the product the night before, as it usually did when futures were nearing expiration.

Mr. Zhang found other investors who lost money, and they demanded compensation. The bank later offered to return a fifth of his original investment and drop the additional sum it claimed he owed. Mr. Zhang, a resident of the coastal city of Zhuhai in southeast China, declined. He wants the bank to return at least half his original investment.

Bank of China said it has asked CME to investigate the day’s moves. Investors could be left with total losses of about $1.3 billion, according to Chinese media outlet Caixin. China’s banking and insurance regulator said it is investigating the product, which the bank has stopped selling. In May, a state-run newspaper quoted a bank executive saying it reached settlements with more than 80% of the investors. Mr. Zhang is still holding out for a better deal.

A CME spokesman said markets worked as designed. The exchange operator told traders in early April that it was prepared for subzero prices. At about 1 p.m. ET on April 20, CME sent a notice to traders saying May futures could turn negative.

As ordinary people faced mounting losses, some professionals were scoring huge returns.

Vincent Elbhar, co-founder of Swiss hedge fund GZC Investment Management AG, sold put options, a form of insurance against falling prices, on April 21—a day he counts as one of the best in his career.

“I was set up for this,” he said.

When the U.S. Oil Fund said that day it would move more of its holdings to later-dated contracts by selling June futures and buying others, New York-based Massar Capital Management LP also sold the June futures and bet that the gap between contracts with different expiry dates would widen.

“The only ‘way out’ for the ETF requires a set of trades that have to be massive in scope,” Marwan Younes, Massar’s chief investment officer, said in an email to investors that morning.

The U.S. Oil Fund has since restructured following pressure from exchanges and regulators. A class-action lawsuit was filed on June 19 against the ETF, the company that operates it—United States Commodity Funds LLC—and that firm’s CEO and chief financial officer in the Southern District of New York. The complaint alleges the fund offered new shares in March without properly disclosing extraordinary market conditions to investors.

A USCF spokeswoman said the company believes the claim is without merit and would move for its dismissal.

Some other oil products like Barclays PLC’s iPath Series B S&P GSCI Crude Oil ETN have suspended sales or closed altogether.

The Commodity Futures Trading Commission issued a public advisory in late May highlighting the risks of trading commodity products, but for many investors it was too late.

Several days after the April 20 crash, a representative of Mr. Cho’s brokerage, Kiwoom Securities Co., said he could settle his positions to pay just over $7,000, down from the maximum possible loss of $56,000.

Instead, he made a sign reading “Every day is hell for the victims! Compensate immediately!” and protested at Kiwoom’s Seoul headquarters. That got him a meeting with the firm’s chief executive. Mr. Cho eventually accepted the offer to pay more than $7,000.

Kiwoom has nearly finished providing compensation for about 50 similar cases and expects its losses to total over 1 billion won ($818,000), a spokesman said.

“It was all really absurd,” Mr. Cho said. “I felt that they were the ones who messed up, but I had to pay the price.”

Updated: 7-6-2020

Behind Oil’s Rise Is a Historic Drop in U.S. Crude Output

U.S. crude supply is falling at its quickest pace ever, easing a global oil glut and spurring a swift recovery in fuel prices.

Yet oil’s push back above $40 a barrel as drivers return to roads isn’t enough for beleaguered shale producers, which until recently were the driving force behind a transformation of the global energy industry. For many of them, prices haven’t risen far enough to help ease the strain of debt taken on during boom times. And the need to cut output in the face of pandemic-hit demand means they can’t pump their way out of trouble.

Weekly U.S. output recently fell to 10.5 million barrels a day, down from a near-record of 13 million barrels a day from late March, government data show. With companies from Chevron Corp. to Continental Resources Inc. shutting in productive wells in response to the coronavirus, the slide marks the biggest 11-week drop on record in figures going back to 1983.

In percentage terms, the decline is the biggest since the 2008 financial crisis, when U.S. oil output was less than half of what it is now.

The tumble in domestic supply and record output cuts from the Organization of the Petroleum Exporting Countries and partners including Russia are supporting oil prices after they collapsed earlier in the year.

Even with the recent rebound, oil prices are still well below where they started 2020, and many investors still expect a wave of bankruptcies and industry deals that overhauls the U.S. energy sector.

“I don’t think that $40 oil is enough to turn around the shale industry,” said Andy Lipow, president of Houston-based consulting firm Lipow Oil Associates. “This price is still not enough to cover all the debt and costs that have been incurred during the boom.”

Domestic crude output has since risen back to 11 million barrels a day, but some analysts expect supply declines to persist moving forward.

As a result, U.S. crude on Friday closed at $40.65 a barrel—its highest level since early March. Prices inched down to $40.63 Monday but in recent weeks have pared some of their 2020 decline after starting the year above $60. Prices briefly turned negative in late April due to a global glut.

The rebound remains tenuous because coronavirus cases continue to climb in many large fuel-consuming states including Texas, California and Florida. Adding to the energy industry’s woes: Prices for natural gas recently hit a roughly 25-year low, with the pandemic sapping demand for the power-generation fuel.

The turmoil is rippling through the sector. A recent Deloitte LLP analysis found that shale companies, such as Occidental Petroleum Corp. and Concho Resources Inc., could have to impair or write down the value of their assets by as much as $300 billion. The industry burned through tens of billions of dollars annually in recent years to increase production, and many companies took on hefty amounts of debt.

Analysts are now debating which companies with lower costs will make it through the crisis. Many expect a bifurcation between that group and firms with too much debt to survive.

“I would call it a transformation,” said Rebecca Babin, senior energy trader at CIBC Private Wealth Management. “You will continue to see bankruptcy and continue to see consolidation.”

North American oil-and-gas producers, pipeline operators and oil-field-service companies have more than $240 billion in debt maturing over the next five years, according to Moody’s Investors Service.

Denver-based Whiting Petroleum Corp. became the first major shale bankruptcy of the pandemic earlier this year. Industry pioneer Chesapeake Energy Corp. filed for bankruptcy protection on June 28, and analysts say more producers likely will follow.

The oil-price rebound “has maybe given a little bit of timing breathing room but ultimately hasn’t really changed the economics of some of these assets,” said Scott Sanderson, a principal in Deloitte’s oil-and-gas strategy and operations practice.

Shares of S&P 500 energy producers have fallen 38% this year, though they remain up solidly from a low hit in March. Some companies including ConocoPhillips, Parsley Energy Inc. and EOG Resources Inc. already have laid out plans to begin increasing supply in response to higher oil prices and traders say it is inevitable that producers would respond if the rally continues.

But even with those increases from existing wells, many investors expect a plunge in new drilling activity to damp U.S. crude output moving forward. The number of wells drilling for oil in the U.S. has tumbled to 185, its lowest level in more than a decade and a fraction of the total from the start of the year, figures from Baker Hughes show.

“We expect [exploration-and-production companies] in general to remain capital disciplined and focused on the balance sheet,” Continental Resources Chief Executive William Berry said at a recent JPMorgan Chase virtual industry conference. Continental has been substantially curtailing its oil production lately.

In addition to U.S. output, traders are closely monitoring supply from OPEC and its partners to see if global producers also are responding to the price rebound.

Many OPEC members such as Saudi Arabia need much higher oil prices to balance their budgets, according to International Monetary Fund data, and the cartel recently has indicated a willingness to continue curbing output given the continuing uncertainty caused by the pandemic.

“The shale industry knows that OPEC+ still has shut in a significant amount of oil production that could easily return to the market,” Mr. Lipow said. “That’s one of the reasons for them remaining cautious.”

Updated: 7-6-2020

Companies Cancel Atlantic Coast Pipeline After Years of Delays

Duke Energy and Dominion Energy said the prospects of a natural gas conduit under the Appalachian Trail remained too uncertain.

The builders of the Atlantic Coast Pipeline are pulling the plug on the project as companies continue to meet mounting environmental opposition to new fossil-fuel conduits.

Duke Energy Corp. and Dominion Energy Inc. said Sunday they were abandoning the proposed $8 billion pipeline—which aimed to carry natural gas 600 miles through West Virginia, Virginia and North Carolina and underneath the Appalachian Trail—citing continued regulatory delays and uncertainty, even after a favorable Supreme Court ruling last month.

Dominion said it was selling the rest of its natural-gas transmission and storage network to Warren Buffett’s Berkshire Hathaway Inc. for $9.7 billion including debt. The deal includes a 25% stake in the Cove Point liquefied natural gas export facility in Maryland, of which Dominion will remain the largest owner.

“This announcement reflects the increasing legal uncertainty that overhangs large-scale energy and industrial infrastructure development in the United States,” Dominion and Duke said in a joint statement. “Until these issues are resolved, the ability to satisfy the country’s energy needs will be significantly challenged.”

Utilities and pipeline companies have been trying to expand U.S. pipeline networks for more than a decade to take advantage of the bounty of oil and gas unlocked by the fracking boom.

But many of the projects have encountered intense opposition from landowners, Native American groups and environmental activists concerned about climate change who want to keep fossil fuels in the ground.

The Keystone XL pipeline expansion to carry oil from Canada to the U.S. Gulf Coast remains unbuilt more than a decade after it was proposed by TC Energy Corp. The operator of the Dakota Access pipeline, Energy Transfer LP, completed the conduit to carry oil from North Dakota’s Bakken Shale region to Illinois in 2017 after years of protests and delays.

The Trump administration has sought to make it easier for companies to build pipelines and other energy infrastructure, but the effort has failed to fast-track projects amid continued legal and regulatory challenges by opponents.

Dominion and Duke had first proposed building the Atlantic Coast Pipeline in 2014. It repeatedly faced legal challenges from environmentalists, Native American groups and others. Its costs had swelled to $8 billion before the companies decided to abort the plan.

“Duke and Dominion did not decide to cancel the Atlantic Coast Pipeline—the people and frontline organizations that led this fight for years forced them into walking away,” said Michael Brune, the executive director of the Sierra Club.

The companies had scored a significant victory last month when the Supreme Court ruled that it could cut under the historic Appalachian Trail, which runs from Georgia to Maine. The court overturned a lower-court ruling that found the U.S. Forest Service didn’t have the authority to grant a special-use permit that allowed for the development of that segment.

However, Duke and Dominion said Sunday that the ruling wasn’t enough to mitigate an “unacceptable layer of uncertainty and anticipated delays” for the project. They cited a Montana court ruling last month that threw another roadblock in the path of the Keystone XL Pipeline as an example of the continued challenges such projects face.

That ruling, which related to a federal permit program for oil and gas pipelines, had the potential to also further delay the Atlantic Coast Pipeline, the companies said. The companies involved had together invested about $3.4 billion in the pipeline to date.

Duke, based in Charlotte, N.C., provides electric and gas service to more than nine million customers in the Carolinas, Midwest, Florida and Tennessee.

Dominion, based in Richmond, Va., provides electricity or natural gas to about seven million customers in 20 states. It will almost entirely exit from its gas-transmission business with the sale of its pipeline and storage assets to Berkshire Hathaway Energy.

As part of the deal, Berkshire Hathaway Energy will acquire Dominion Energy Transmission, Questar Pipeline and Carolina Gas Transmission as well as a 50% stake in Iroquois Gas Transmission System.

Berkshire Hathaway Energy will also acquire 25% of Cove Point LNG, one of six liquefied natural gas export facilities in the U.S. Dominion will retain a 50% stake in the project, with Brookfield Asset Management owning the remaining 25%.

Berkshire Hathaway Energy operates a $100 billion portfolio of utility, transmission and generation businesses providing natural gas and electricity to more than 12 million customers. The Dominion acquisition will add 7,700 miles of natural-gas storage and transmission pipelines and about 900 billion cubic feet of gas storage to its holdings.

“Acquiring this portfolio of natural gas assets considerably expands our company’s footprint in several Eastern and Western states as well as globally,” Bill Fehrman, Berkshire Hathaway Energy’s president and chief executive, said.

The $9.7 billion transaction includes $5.7 billion in debt. It is expected to close in the fourth quarter.

Dominion said the sale will allow it to focus on its state-regulated gas and electric utilities. It expects those businesses, primarily those serving Virginia, Ohio, Utah and the Carolinas will account for as much as 90% of future operating earnings.

Dominion and Duke have each been pushing to slash their carbon emissions in response to state mandates and customer concerns about climate change. Both companies are aiming for net-zero carbon emissions by 2050 by developing more wind and solar power and investing in other clean technologies.

Duke said that it plans to invest in renewable-energy, battery storage and energy efficiency programs as it works to find cleaner ways to generate power.

“While we’re disappointed that we’re not able to move forward with ACP, we will continue exploring ways to help our customers and communities, particularly in eastern North Carolina where the need is great,” Chief Executive Lynn Good said in a statement.

Updated: 7-14-2020

Universities Cut Oil Investments As Student Activism Builds

Push for large-scale divestment at colleges marks the latest blow to companies; some call it counterproductive.

When the University of Michigan’s chief financial officer asked the school’s Board of Regents in December to authorize a new $50 million oil-and-gas investment, they gave an answer he had never heard before: No.

The board delivered the news at a meeting packed with student activists. They had spent months pushing the university to stop funding fossil-fuel companies. A few weeks later, the school said it was freezing all direct investments in such companies.

U.S. university and college endowments control more than $600 billion of investments, and the movement to divest those funds from fossil fuels is gaining momentum—even though the pandemic has kept students off many campuses and issues of racial injustice have dominated the national discourse since George Floyd was killed in police custody in May.

Activists say years of alarm about the costs of climate change have unified a broad base of support, including among the alumni that typically fund endowments. Big universities rarely capitulate to such campaigns and fossil fuels seem to be joining a very short list of investments deemed off-limits by the ivory tower, such as apartheid-era South Africa and tobacco products.

In May, Cornell University swore off new direct investments in oil and gas, and George Washington University decided in late June to divest from the industry entirely following a similar action by Georgetown University in February. Alumni of Harvard University are voting this month on whether to appoint pro-divestment candidates to the board of overseers, which votes on the membership of the corporation that supervises its endowment, the largest in the country at about $40 billion.

“I’m going to be honest, I didn’t think we’d get this far,” said Jayson Toweh, an Environmental Protection Agency program analyst and Harvard alumnus who is one of the candidates. “The process just to get nominated as a candidate was very arduous and made complicated, in my opinion, to keep us off the ballot.”

Even Yale University’s rock-star endowment headDavid Swensen is feeling the pressure. An opponent of divestment, Mr. Swensen agreed to meet with the school’s faculty senate and students in February for a public debate on the issue, his first such meeting in 35 years at the university. The endowment’s natural-resource investments declined to a 10-year low of about 5% in 2019 from 7% the prior year.

Mr. Swensen and Harvard President Lawrence Bacow both published open letters this year favoring proactive engagement with the energy industry to reduce carbon emissions.

The push for large-scale divestment by colleges marks the latest blow to big oil companies, which are already reeling from a price crash and a broad effort to move toward low-carbon technologies. Shifts by endowments often sway the behavior of public pensions, which control about $4 trillion in assets, according to data from the National Association of State Retirement Administrators.

The Independent Petroleum Association of America, a trade group, has launched a media campaign against divestment, arguing that it would cost U.S. pensions as much as $431 million in losses annually.

Some in academia are pursuing divestment as a way to influence national policy on climate change, much like the antiapartheid movement on campus helped spur U.S. sanctions against South Africa in the 1980s.

“Our university can be a model for others,” said Mark Bernstein, a trial lawyer who serves on the University of Michigan’s board of regents. “We have to do everything we possibly can to disrupt the flow of carbon into the atmosphere, and that includes disrupting the flow of capital to the fossil-fuel industry.”

Others see it as a necessary step to reduce the risk of investment losses. Shares of Exxon Mobil Corp. have lost nearly half of their value since the start of 2018.

“I don’t think it’s a political issue; it’s an issue of what’s best for the university,” said Ron Weiser, a former chairman of the Michigan Republican Party who is also a regent at the University of Michigan. “Some institutions have come to the conclusion that the long-term risk of investing in fossil fuels is substantial.”

The approach still has detractors, even among sustainable-investing advocates. Divestment is counterproductive, they say, because institutions that adopt it abdicate their ability to influence large energy companies such as Exxon Mobil.

“Divestment is a fancy word for selling your shares,” said Anne Simpson, a director for sustainable investments at California Public Employees’ Retirement System, or Calpers, which managed $383 billion in May. “We are using our position as owners of these companies to drive change. Walking away from a situation is not going to change it.”

Environmental advocacy groups such as 350.org helped launch the university divestment movement around 2012, aiming to slow global warming by stopping oil-and-gas companies from extracting their known fossil-fuel reserves. Most large U.S. schools resisted the idea, fearing that it would damp their financial returns and embolden activists to push for divestment from a much broader swath of investments.

“Conceiving of the endowment not as an economic resource, but as a tool to inject the University into the political process or as a lever to exert economic pressure for social purposes, can entail serious risks,” Harvard’s then-president Drew Gilpin Faust said in 2013.

Brown University, The New School, Whitman College and some others such as Syracuse University adopted the measure. Most others, including Cornell, Harvard, Stanford University, University of Michigan and University of Pennsylvania rejected proposals from their students and faculty to divest.

“There seems to be an arrogance by the people investing the university’s money,” said Anne Sobol, a former lawyer who graduated from Harvard in 1967 and now volunteers for Harvard Forward, the organization behind Mr. Toweh’s candidacy. “The implication is that people like us just don’t understand what’s best.”

College of the Atlantic, a small ecology-focused school in Maine, was one of the few educational institutions to fully divest in 2013. The college has a relatively small endowment of $67 million. But from 2013 to 2019 it averaged an 11.8% return, compared with 10.5% by the MSCI stock index, which included fossil-fuel companies, said Henry Schmelzer, one of the school’s trustees.

“We didn’t plan it this way,” Mr. Schmelzer said. “It happened because of the wall of trouble the energy industry has been having.”

The rise of shale production and alternative-energy sources have gutted fossil-fuel prices over the past five years, at the same time that concern about climate change has grown, even within the Republican party and on Wall Street.

Those changes have reinvigorated the divestment movements in many large schools.

University of Michigan President Mark Schlissel rejected a divestment initiative in 2015, saying the university used fossil fuels to operate and that oil-and-gas companies weren’t as ethically problematic as businesses tied to apartheid. The school’s endowment grew by about 20% to $12 billion in 2019, but investment returns underperformed the S&P 500 stock index, which averaged annual returns of 10.6% over the same period.

Investment in natural resources, primarily fossil fuels, accounted for about 9% of the university’s total investments in 2019, according to its annual report. The average is 7.7% for U.S. endowments, according to data from Yale University. The University of Michigan averaged annual returns of 6.5% in the five years ended in June 2019, beating the 5.9% return of its custom benchmark index, according to a report by the school’s chief financial officer.

A new drive for divestment gained steam on the University of Michigan campus in 2019. Student activists occupied an administration building in March, leading to several arrests, and began protesting regularly at the monthly meetings of the board of regents. When they learned that Chief Investment Officer Erik Lundberg wanted to make a $50 million investment in a fund focused on oil and gas they canvassed the regents to reject the idea, which they did at a Dec. 5 meeting.

“It felt amazing,” said Noah Weaverdyck, one of the students arrested in March who helps lead the divestment movement.

The euphoria proved short-lived. The university in February said it was placing a moratorium on future direct fossil-fuel investments but hasn’t budged on divesting the $1.3 billion of natural-resource investments it still holds.

“The freeze was only won after years of work and constant pressure.” Mr. Weaverdyck said. “Direct, collective disruptive action has been the only thing to actually achieve results.”

Updated: 7-24-2020

Schlumberger Cuts 21,000 Jobs Amid Historic Oil Downturn

Top oil-field services provider books $3.7 billion in charges as coronavirus pandemic slams its business.

Schlumberger Ltd., SLB -1.58% the world’s largest oil-field services company, is cutting about 21,000 jobs as oil producers slash spending in response to a historic drop in prices amid the coronavirus pandemic.

Schlumberger said Friday that it recorded $3.7 billion in impairment charges in the second quarter, including about $1 billion related to the job cuts, which represent roughly one-fifth of its workforce.

“This has probably been the most challenging quarter in past decades,” Chief Executive Olivier Le Peuch said, noting revenue fell sharply because of an unprecedented fall in oil-field activity in North America.

Schlumberger’s sweeping workforce reduction is the latest example of how companies are having to sharply tighten their belts and cut staff as demand for their products and services plummets due to the pandemic.

From United Airlines Holdings Inc. and Boeing Co. to General Electric Co. and Uber Technologies Inc., dozens of major companies have announced they are laying off workers as they buckle down in anticipation of a prolonged slowdown.

Many companies have chosen to furlough rather than completely sever ties with workers in hopes of bringing them back when conditions improve. But as the effects of the pandemic drag on, more employers may resort to letting workers go.

Energy companies have been particularly hard-hit. U.S. oil prices dropped into negative territory for the first time in April as demand for gasoline and jet fuel fell dramatically this spring after people stopped traveling and governments imposed stay-at-home restrictions.

The oil price crash prompted U.S. oil companies to sharply cut capital spending on drilling and fracking new wells, the lifeblood of oil-field service companies such as Schlumberger and rivals Halliburton Co. and Baker Hughes Co.

Earlier this week, Halliburton and Baker Hughes both reported losses and declining revenue for the second quarter, with Halliburton estimating spending by North American oil-field services customers will decline 50% this year compared with 2019.

Schlumberger’s Mr. Le Peuch said the company has accelerated a plan to restructure its North American business, shutting down scores of facilities in a move to position itself “for a market of smaller scale and lower growth outlook, but with higher returns.”

He said oil demand is slowly returning to normal and is expected to improve as governments lift restrictions in support of increased consumption, paving the way for a modest pickup in fracking activity in North America.

“We expect the global decline to recede into a soft landing in the coming months absent further negative impact from Covid-19 on the economic recovery,” Mr. Le Peuch said in a conference call Friday.

As many as 55,000 of the company’s employees are working remotely, he said. Schlumberger has corporate offices in Paris, Houston, London and The Hague.

For the second quarter, Schlumberger reported a net loss of $3.4 billion, or $2.47 a share, compared with a profit of $492 million, or 35 cents a share, in the same period last year. Revenue declined 35% to $5.4 billion, with North American sales dropping 58% to about $1.2 billion.

Earnings per share, excluding charges and credits, came to 5 cents. Analysts polled by FactSet were expecting a loss of a penny a share.

Schlumberger said it employed approximately 85,000 people as of the end of the second quarter. It had said in the first quarter it employed about 103,000.

Halliburton has also cut thousands of jobs, reporting Monday that it had more than 40,000 employees as of the end of the second quarter, down from about 55,000 at the end of the fourth quarter. It didn’t provide specific job-cut numbers.

“This was a difficult decision, but is a necessary action as we work to successfully adapt to challenging market conditions,” Halliburton spokeswoman Emily Mir said.

Last month, British oil giant BP PLC said it plans to cut nearly 10,000 jobs, or 14% of its workforce. U.S. oil major Chevron Corp. has said it expects to reduce its global workforce of about 45,000 by 10% to 15%, with most of the reduction taking place this year.

Updated: 7-30-2020

Shell Swings To Historic Loss As Pandemic Devastates Oil Demand

Anglo-Dutch oil major warns that uncertain demand outlook could curtail its third-quarter production.

Royal Dutch Shell PLC swung to a heavy loss in the second quarter and warned that the outlook for oil-and-gas demand continued to be uncertain, illustrating the scale of damage Covid-19 is wreaking on the industry.

The pandemic has decimated demand for oil, hitting prices hard. When around two-thirds of the world’s population was in lockdown in early April, global oil demand fell by a third, according to the International Energy Agency.

That led Shell on Thursday to report a second-quarter loss on a net current-cost-of-supplies basis—a figure similar to the net income that U.S. oil companies report—of $18.4 billion. That compares to a profit of $3 billion in the same period last year and is the company’s first loss since the third quarter of 2015.

Tough Times

The world’s big five oil companies typically pay reliable dividends, other than in rare times of crisis.

The Anglo-Dutch company’s performance was partly hit by it writing down the value of its assets by $22 billion before tax, as flagged in June, reflecting expectations of lower energy prices.

About half the charge was attributed to its gas business—mainly its Australian liquefied natural gas projects. It also wrote down the value of two shale assets in North America and offshore assets in Brazil, Europe, Nigeria and the Gulf of Mexico.

Shell warned that the uncertain outlook for oil and gas demand could curtail its production in the third quarter, as well as activity at its refineries and chemicals plants. It also said its LNG business would suffer a greater impact from lower oil prices in the third quarter because of the time lag for price moves reaching oil-linked LNG contracts.

Benchmark Brent oil prices averaged $29.60 a barrel between April and June, down 57% from the comparable period a year earlier.

Brent traded at $43.78 a barrel Thursday.

“There remains continued significant uncertainty in terms of how the pandemic will play out, we’re seeing a lot of starting and stopping around the world, that impacts our assets, our supply chains,” said Jessica Uhl, Shell’s chief financial officer.

The company is restructuring to become simpler, leaner and more focused, Ms. Uhl said, without elaborating on whether this could result in Shell selling any businesses. Efforts to reduce costs include a voluntary redundancy program, although the company didn’t say how many roles could be cut. Shell employs around 83,000 people.

“A major overhaul is required, working out what’s core and noncore, in the context of whether they want to be in all markets or exit some businesses,” said Christyan Malek, an analyst at JP Morgan.French energy company Total SA TOT -0.08% also reported a quarterly loss Thursday, but said it would maintain its dividend.

Its earnings came a day after it wrote down the value of its assets by $8.1 billion because of lower oil price expectations. Still, Total said that while its European gas stations saw a 30% fall in demand for petroleum products in the quarter, by June it had rebounded to 90% of precrisis levels.

Both Shell and Total noted the strength of their trading activities, which can make money even when energy prices are lower by taking advantage of price volatility. Ms. Uhl said it was one of Shell’s best trading performances on record.

The two European companies are the first of the five major oil companies to detail the damage the pandemic has inflicted during the second quarter.

U.S. giants Exxon Mobil Corp. and Chevron Corp. are expected to report quarterly losses Friday, with Exxon warning recently that it faced steep losses in its refining and production businesses.

Oil companies have taken swift action to shore up their finances since coronavirus struck, including cutting costs and reducing staff. Shell has been among the most aggressive, deciding in April to cut its dividend for the first time since World War II to avoid having to borrow to fund it.

The company said that as its earnings recover it would look to increase dividends, expand investment to enable growth and reduce debt.

Shell said Thursday that its gearing level—net debt as a percentage of total capital—rose to around 33%, above the company’s target of 25%. In April Shell’s gearing was 29%. Higher gearing can raise the cost of borrowing for a company.

Both Exxon and Chevron have said they are committed to not cutting dividends, but have taken on more debt this year. Analysts expect BP PLC to cut its payout to shareholders when it reports earnings Tuesday.

Updated: 7-31-2020

Big Oil Companies Lose Billions, Prepare For Prolonged Pandemic

Exxon, Chevron join procession of oil giants reporting dismal second-quarter results as the coronavirus continues to reduce the world’s thirst for oil and gas.

Big oil companies endured one of their worst second quarters ever and are positioning themselves for prolonged pain as the coronavirus pandemic continues to sap global demand for fossil fuels.

Exxon Mobil Corp. posted a quarterly loss for the second straight quarter for the first time this century on Friday, reporting a loss of $1.1 billion, compared with a profit of $3.1 billion a year ago. Exxon, the largest U.S. oil company, hadn’t reported back-to-back losses for at least 22 years, according to Dow Jones Market Data, whose figures extend to 1998.

“The global pandemic and oversupply conditions significantly impacted our second-quarter financial results with lower prices, margins, and sales volumes,” Exxon Chief Executive Darren Woods said.

Chevron Corp. said Friday it lost $8.3 billion in the second quarter, down from $4.3 billion in profits during the same period last year, its largest loss since at least 1998. It wrote down $5.7 billion in oil-and-gas properties, including $2.6 billion in Venezuela, citing uncertainty in the country ruled by strongman Nicolás Maduro. Chevron also said it lowered its internal estimates for future commodity prices.

Royal Dutch Shell PLC and Total reported significant losses in the second quarter earlier this week, as the impact of the pandemic and a worsening long-term outlook for commodity prices spurred them to write down the value of their assets.

The dismal results are ratcheting up the problems for the oil giants, which were struggling to attract investors even before the pandemic, as concerns over climate-change regulations and increasing competition from renewable energy and electric vehicles cloud the future for fossil fuels.

Holdings of oil-and-gas stocks by active money managers are at a 15-year low, according to investment bank Evercore ISI. BP PLC, Shell and Total are all trading at 30-year lows relative to the overall S&P 500. Exxon is trading at its lowest level to the S&P 500 since 1977, according to the bank.

Many of the big oil companies have sought to retain investors despite slowing growth and profits over the past decade by paying out hefty dividends, but those payouts are proving hard to sustain during the pandemic.

Crude prices have stabilized at around $40 a barrel, providing modest relief for the industry after U.S. oil prices briefly turned negative for the first time ever in April. But none of the world’s largest oil companies now foresee a rapid recovery as countries continue to struggle with containing the coronavirus.

Chevron CEO Mike Wirth said his company faced an uncertain future for energy demand and couldn’t predict commodity prices with confidence right now.

“We expect a choppy economy and a choppy market,” Mr. Wirth said in an interview earlier in July. “It all depends on the virus and the policies enacted to respond to it.”

Oil and gas production by both Exxon and Chevron decreased in the quarter, down 7% and 3%, respectively, from a year ago, as the companies shut off wells to avoid selling into a weak market. Exxon’s production-and-exploration business lost $1.7 billion, which Exxon attributed to lower commodity prices. Chevron’s production unit lost $6.1 billion.

U.S. oil prices closed below $40 per barrel Thursday for the first time in three weeks.

For the entire second quarter, U.S. oil prices averaged $28 per barrel and Brent crude averaged about $33, according to Dow Jones Market Data, prices at which even the largest oil companies struggle to turn a profit, analysts say.

While major stock indexes have recovered from April, when they fell to their lowest levels in years, oil and gas stocks have continued to lag despite the slight rebound in commodity prices.

Many of the world’s largest energy companies, including Exxon and Chevron, have for years used an integrated business model, which has historically allowed them to weather most market conditions.

By owning oil and gas wells, along with the downstream plants to manufacture refined products like gasoline and chemicals, the companies were long able to capitalize in one sector of their business, regardless of whether oil prices were high or low.

But that model has failed to deliver strong returns for most of the past decade, as the world has faced a glut of fossil fuels triggered in part by America’s fracking boom, and it isn’t protecting the companies now, according to Evercore ISI analyst Doug Terreson.

“A broad-based reassessment of the capital-management programs at the big oils is required at this point,” Mr. Terreson said.

Oil companies have been forced to take dramatic action to shore up their finances in recent months, including cutting tens of billions of dollars from their budgets and laying off thousands of employees.

Exxon, which had previously disclosed a 30% cut to capital expenditures in 2020, said on Friday it has “identified significant potential for additional reductions” and said capital spending in 2021 will be lower than this year’s spending.

Its steepest cuts have been to U.S. shale drilling, particularly in the Permian Basin, the most active U.S. oil field, where it removed half of its drilling rigs and will cut half of the remaining 30 rigs by the end of year. Chevron is operating just four rigs in the Permian and said production there would decline around 7% this year.

Shell in April cut its dividend for the first time since World War II to avoid having to borrow to fund it. It reported a second-quarter loss of $18.4 billion on Thursday, which included a $16.8 billion write-down, while French giant Total posted an $8.4 billion loss including an $8.1 billion write-down. Both companies report net income attributable to shareholders, a proxy for net profits. BP reports Tuesday.

Excluding impairments, Shell and Total actually turned a profit during the quarter as their trading units helped stave off even larger losses.

Exxon and Chevron have promised they will maintain their dividends, viewed by many investors as the most attractive part of owning their stocks. Some analysts predict Exxon may be forced to cut its dividend in 2021 if market conditions don’t recover.

Exxon’s dividend payments cost the company almost $15 billion a year. The company’s debt grew by $8.8 billion in the quarter, according to Goldman Sach Group Inc., which said Exxon will need oil prices around $75 per barrel in 2021 to cover its dividend payments from cash flow. Exxon said Friday it wouldn’t take on additional debt.

Dan Pickering, chief investment officer of energy investment firm Pickering Energy Partners LP, said the industry can survive at $40 oil but needs significantly higher prices to thrive. According to Mr. Pickering, who said he holds small positions in Exxon and Chevron, oil companies will have to continue cost-cutting for the foreseeable future.

“You’ve got to assume that this is the world we’re going to be in, Mr. Pickering said. “And, if this is the world we’re going to be in, the cost structure is too high.”

Updated: 8-3-2020

Refiners Retrench As Demand For Gasoline, Jet Fuel Shrivels

U.S. fuel makers ran below capacity in the second quarter in a preview of the challenges they are likely to face as the world transitions away from fossil fuels.

U.S. fuel makers slashed production during the second quarter as they reeled from a historic decline in demand for gasoline and jet fuel.

Long a bright spot in the oil patch, refiners such as Valero Energy Corp., Marathon Petroleum Corp. and Phillips 66 pumped the brakes as the coronavirus pandemic kept people off the roads and out of the skies, crushing demand for the fuels they produce.

U.S. consumption of gasoline and distillates including diesel has rebounded from its April trough to more than 90% of year-ago levels, Energy Information Administration data show. But demand for jet fuel remains anemic, at little more than half of last year’s level, a sign that global oil demand is likely to remain depressed for years.

World-wide, fuel makers have coped by processing far less crude, shutting down some facilities and constraining spending. This year’s average global refinery utilization rates are expected to be the lowest in 37 years, according to the International Energy Agency. Refiners typically make less money when they operate well below capacity because the cost of running their facilities doesn’t decline by much.

In the latest sign of pressure on the sector, Marathon told employees Friday that it has no plans to restart two refineries that it idled in April. The company had tried unsuccessfully to sell one of the facilities, Chief Executive Michael Hennigan said Monday.

Marathon on Sunday evening also announced that it was selling its gas-station business to the owner of the 7-Eleven convenience store chain for $21 billion in the largest U.S. energy-related deal so far this year.

U.S. refiners’ second-quarter results provide a glimpse of the challenging future that fuel makers face as tougher fuel-efficiency requirements and electric vehicles threaten their businesses. That is the reality already facing refiners in Europe, where demand for transportation fuels had fallen even before the pandemic.

“To a degree, the pandemic is a harbinger of the coming energy transition more broadly, where oil demand declines year after year,” said Kurt Barrow, a vice president at analytics firm IHS Markit.

Phillips 66 ran its refineries at 75% of capacity during the second quarter, down from 97% in the same period a year earlier. Its refining business lost $878 million pretax during the period, whereas in the year-ago period it generated $983 million in pretax profit.

The company’s margin on each barrel of oil that it processed fell to $2.60 from $11.37 a year earlier. That contributed to a second-quarter loss of $141 million, compared with profit of $1.4 billion in the year-ago period.

Valero processed some 22% less crude during the second quarter than it did a year earlier, and its margin per barrel fell to $5.10 from $9.58. The company largely reversed the $2.5 billion inventory write-down that it took during the first quarter, as oil prices roughly doubled from the end of March to the end of June.

That reversal helped to lift Valero’s second-quarter profit to $1.3 billion from $612 million in the year-ago period. Excluding one-time adjustments, the company reported a $504 million loss, compared with $665 million in profit during the same period last year.

Valero executives said the company is refining more oil to meet improving demand but cautioned that jet-fuel consumption remains severely depressed.

“That would be the only sign that we’re seeing that’s a little bit troubling,” Valero Chief Commercial Officer Gary Simmons told investors last week.

Many observers expect jet-fuel consumption to remain low for years, as people avoid flying because of the coronavirus and businesses conduct more meetings by videoconference, constraining global oil demand.

By the end of next year, the IEA expects world oil consumption will be about 2% below levels from late 2019. Some refineries likely will have to shut down, much as they did after the 2007-09 recession, when some eight million barrels a day of refining capacity permanently closed, according to the IEA.

“There is going to be continued rationalization,” Thomas Nimbley, chief executive of New Jersey-based PBF Energy Inc., told investors last week.

PBF ran about 21% less oil through its systems during the second quarter than it did a year earlier as its margin on each barrel plummeted to $1.54 from $9.10. The company generated $413 million in second-quarter profit versus a year-ago loss of $22 million, thanks in part to asset sales and an increase in inventory value.

Mr. Nimbley said PBF is focused on weathering the pandemic and reducing debt, at which point it will look to diversify into areas such as renewable diesel, a fuel made from products such as vegetable oil or grease.

Refiners are increasingly interested in alternative fuels. Marathon, for example, is considering converting one of the refineries it closed this spring to a facility that produces renewable diesel.

Marathon ran its refineries at 71% of capacity during the quarter, down from 97% during the same period a year earlier. Its margin-per-barrel declined to $7.13, from $15.24 a year earlier.

The company partially reversed a $3.2 billion inventory charge it took earlier this year, helping to lift first-quarter profits to $9 million, compared with $1.1 billion a year prior. Excluding one-time adjustments, Marathon had a quarterly loss of $868 million, compared with a $1.1 billion profit a year earlier.

IHS, the analytics firm, expects global oil consumption will surpass 2019 levels in 2023 and continue to grow at least through the end of the decade, yet remain far lower than it would have been had the pandemic never happened. Others such as Rystad Energy think world oil demand will peak before the end of the decade as electric vehicles gain market share and people travel less.

Either scenario is challenging for fuel makers.

U.S. refining companies raked in cash in recent years, despite relatively flat domestic fuel consumption, because of an uptick in exports and a shale boom that outpaced domestic pipeline infrastructure. Soaring production created crude bottlenecks in pockets of the U.S. and regional price dislocations that fuel makers took advantage of.

Such severe regional price disparities are unlikely to re-emerge soon because U.S. oil production has fallen to around 11 million barrels a day, from some 13 million barrels a day earlier this year, relieving pressure on the conduits that move crude around the country, said Sandy Fielden, director of oil and products research for Morningstar Inc. For those looking to unload weaker assets, buyers are few and far between.

“They’re in the same boat as the European refiners have been in for years, which is too many refineries, not enough demand,” Mr. Fielden said.

Updated: 8-4-2020

BP Reports $17.7 Billion Loss, Cuts Dividend

British energy giant’s decision caps one of the worst quarters ever for the world’s biggest oil companies.

BP PLC cut its dividend for the first time in a decade and outlined plans to pivot away from oil and gas and invest more in low carbon energy—marking one of the most dramatic energy-transition plans among its oil major peers at a time of deep crisis for the industry.

The British energy giant aims to increase its low-carbon investments to $5 billion a year by 2030, from around $500 million, at the same time as seeing its oil and gas production fall by 40% from 2019 levels.

The plans include ramping up renewable energy capacity from sources such as wind and solar to 50 gigawatts, from 2.5 GW in 2019.

BP’s decision Tuesday caps one of the worst quarters ever for the world’s biggest oil companies, all of which reported losses and warned of more pain to come as the coronavirus pandemic continues to sap global demand for fossil fuels.

The company’s decision to halve its dividend follows a similar move by Royal Dutch Shell PLC, which said in April it would reduce its dividend by two-thirds. The other major oil companies— Exxon Mobil Corp., Chevron Corp. and Total SA —retained their dividends but have taken on more debt.

Tough Times

The world’s big five oil companies typically pay reliable dividends, other than in rare times of crisis.

The dividend cuts upend what has long been a fundamental bargain between major oil companies and their investors, centered on reliable and large payouts. BP said that the decision to cut the dividend prompted the company to communicate its energy transition plans ahead of its original time frame of September.

“Particularly as we were making the announcement around the dividend, we wanted to give the story all at once, so that people can put all of the decisions in context,” said Bernard Looney, chief executive of BP.

Resetting its dividend at a lower level enables BP to invest in the opportunities arising from the energy transition, the company said. The oil major also plans to sell $25 billion of assets by 2025. The recent sales of BP’s Alaska business and chemicals unit contribute to the target, the company said.

The poor results and dividend cuts come at a time when oil companies were already under pressure from investors to articulate a vision for their future. Demand for fossil fuels is expected to plateau or shrink in the coming years as the world transitions to lower-carbon energy. Companies, including BP and Shell, have questioned whether oil demand will fully recover to pre-pandemic levels, or whether coronavirus could accelerate the transition to greener energy.

This isn’t the first time BP has tried to tilt away from oil and gas. More than a decade ago the company rebranded as “Beyond Petroleum” and committed to generating more renewable energy, but eventually abandoned the effort.

BP said that global oil demand is expected to be around eight to nine million barrels a day lower than in 2019 and that there was potential for weaker energy demand over a sustained period.

The company reported a replacement cost loss—a metric similar to the net income figure that U.S. oil companies report—of $17.7 billion for the three months ended June 30, from a profit of $1.8 billion for the year-earlier period. It reduced its quarterly dividend to 5.25 cents a share from 10.5 cents. The last time BP cut its dividend was in 2010 after the Deepwater Horizon oil spill in the Gulf of Mexico.

BP said its new dividend policy entailed a fixed amount, and it will return at least 60% of surplus cash as share buybacks once the company’s balance sheet has been strengthened.

“We believe that what we are setting out today offers a compelling and attractive long-term proposition for all investors—a reset and resilient dividend with a commitment to share buybacks; profitable growth; and the opportunity to invest in the energy transition,” said Mr. Looney.

BP’s gearing—the ratio of net debt to the total of net debt and equity—fell to just below 38% including leases in the three months to June 30, from around 40% in the previous quarter. It remained above its targeted 20% to 30%.

Updated: 8-10-2020

Mauritius Struggles To Contain Oil Spill From Grounded Cargo Ship

Authorities say the ship may split in two, fueling fears of an environmental disaster.

Authorities in Mauritius fear a damaged Japanese cargo ship carrying 4,000 metric tons of oil and diesel could break and cause an environmental disaster in the waters around the Indian Ocean island nation.

The MV Wakashio, a bulk commodities vessel owned by Nagashiki Shipping Co. and operated by Mitsui OSK Lines, ran aground off the island on July 25, leaving a gaping crack along one side and triggering the leak of 1,000 metric tons of bunker fuel so far along a reef designated by a United Nations agency as a protected site.

Prime Minister Pravind Jugnauth said cracks along the hull of the 984-foot-long vessel had grown and that “the risk of breaking in half still exists.”

Nagashiki Shipping has deployed two tankers to pump the fuel from the Wakashio. Over the past week, locals used straw brooms and sugar cane leaves in an attempt to clean away the spilled oil.

“It’s a race against time to pump the oil out and how much will end up in the sea depends on the tidal shifts,” said Fotis Pagoulatos, an Athens-based naval architect. “The cracks will become wider as it moves and grinds on the ocean floor and it could split up.”

Teams from France and Japan are helping control the spill, with French teams dispatching oil-catching nets, pumps and other equipment from Reunion Island, about 124 miles west of Mauritius.

Mitsui Executive Vice President Akihiko Ono apologized for the spill and “the great trouble we have caused.”

The spill could be disastrous for Mauritius’s economy, which depends heavily on tourism. The disaster site at Pointe d’Esny includes reefs and beaches close to the Blue Bay Marine Park.

Satellite vessel trackers show the Wakashio crossed the Indian Ocean and sailed into Mauritius’s waters two days before the grounding. Authorities are looking into whether its satellite-tracking system malfunctioned and didn’t show that it was heading toward a collision with land.

Updated: 8-12-2020

Oil Demand Faces Bigger Coronavirus Shock Than Previously Thought

OPEC leaves its forecast for a record-breaking rebound in 2021 unchanged.

The coronavirus pandemic will have an even bigger impact on the global economy and its demand for oil than previously expected, the Organization of the Petroleum Exporting Countries said Wednesday.

The cartel estimates that world-wide oil demand this year will amount to 90.6 million barrels a day, 9.1 million barrels less than last year. The 9.1% decline is deeper than OPEC forecast in its previous monthly report.

OPEC also said that it expects a 4% contraction in the global economy, worse than its earlier estimate of 3.7%.

The Vienna-based organization expects economic recovery in all major economies now that lockdowns have eased, but wrote that “the latest surge of infections in the U.S. will need to be closely monitored, as a continuation of this trend may lead to an erosion in rebounding consumer confidence and spending behavior.”

Rising coronavirus cases in India, Brazil and some eurozone countries, such as Spain, also could derail economic growth and oil demand, OPEC said.

The recovery’s vulnerability has kept oil prices stuck in neutral. Both Brent crude futures, the global benchmark, and West Texas Intermediate, the main U.S. gauge, have traded in narrow bands the past two months.

On Wednesday, Brent rose 2.1% to end at $45.43 a barrel. West Texas Intermediate gained 2.5%, to $42.67.

That’s a lot higher than in spring, when U.S. futures prices plunged for the first time ever into negative territory on fears that there would be nowhere left to store oil as Americans hunkered down to slow the spread of the deadly disease. But $40 oil hasn’t been enough to encourage U.S. producers to ramp up output.

The U.S. Energy Information Administration said Wednesday that domestic crude production last week fell to 10.7 million barrels a day, down from a record of 13.1 million in mid-March when governors began issuing stay-at-home orders.

Though jet-fuel consumption remained very weak, down about 45% from a year earlier, demand for diesel and gasoline continued to climb back and chip away at U.S. stockpiles, the EIA said.

Despite the risk of another round of lockdowns, OPEC left intact its forecast for a record-breaking rebound in 2021.

Member nations elected to soften their historic production curbs starting Aug. 1. OPEC and its market allies, such as Russia, will now hold back 7.7 million barrels a day. Saudi, Emirati and Kuwaiti production already have risen.

Questions remain as to whether countries, including Nigeria, that failed to comply with earlier quotas will follow through on pledges to compensate with deeper cuts this month and beyond.

Nigeria’s crude output dropped by 38,000 barrels a day in July, according to official OPEC data, although other data cited in the report shows a decline of just 9,000 barrels a day.

Updated: 8-13-2020

Tankers Waiting For Weeks Off Congested China Ports, Oil Facilities

The growing fleet of idled vessels includes supertankers; together they hold millions of barrels of oil in an oversupplied energy market.

Crude-laden tankers have been lining up for weeks at a time off China’s coast as ports struggle to handle the millions of barrels of inbound oil that have swamped the country’s overfilled storage sites.

Brokers in Shanghai, Singapore and London said at least 80 ships have been waiting for more than a month to unload their cargo in northern Chinese ports including Yingkou, Rizhao and Qingdao, where congestion is the most severe.

More than half of the vessels are very large crude carriers, the workhorses of seaborne oil trade, which can move up to two million barrels each in a single sailing.

China is the world’s biggest oil importer, and as demand for oil has fallen during the coronavirus pandemic, VLCC freight rates have tumbled from an average $129,000 a day in March and $176,000 in April to around $15,400 on the benchmark Middle East-to-China route. That is at least $12,000 below average break-even levels for such ships.

“We had two ships waiting for more than 40 days to unload in Qingdao and Yingkou,” said a Greek owner, who charters tankers to oil majors like Royal Dutch Shell PLC and Exxon Mobil Corp. “The longest we had to wait in the past was a week. They have no space to store the crude and the congestion is severe.”

Up to a quarter of all VLCCs, by industry estimates, have been hired for so-called floating storage, mostly by oil traders looking to sell at higher prices later this year on the belief that oil demand and pricing will recover. The ships stalled off the China coast were hired to deliver their cargoes, however, not for long-term storage.

The Energy Information Administration, the U.S government’s energy statistics office, said in a July 29 report that jet fuel consumption by airlines globally was off 69% in the first two weeks of July compared with the same period last year. Marine shipping trade body Bimco said Americans used 8.6 million barrels of gas per day in the last week of July, down 1 million barrels from a year earlier, based on EIA data.

For the full year, EIA forecasts that global consumption of petroleum and liquid fuels will average 93.1 million barrels per day, down 8 million barrels from last year.

“Reduced economic activity related to the Covid-19 pandemic has caused changes in energy supply and demand patterns in 2020,” the EIA said.

Bimco estimates that freight rates for tankers won’t recover for at least a year.

“There is a massive mismatch between tanker capacity and underlying oil demand,” said Peter Sand, Bimco’s chief shipping analyst. “VLCCs will be mostly loss making for the next 12 to 15 months.”

Updated: 8-17-2020

Interior Secretary Approves Oil Drilling In Alaska’s Arctic Refuge

Decision opens part of the Arctic National Wildlife Refuge to drilling for the first time.

The Trump administration approved an oil leasing program for the Arctic National Wildlife Refuge on Monday, opening up the pristine 19-million-acre wilderness to drilling for the first time and making it difficult to unwind the decision should Democrats recapture the White House in November.

Approving the program clears the way to auction oil leases “right around the end of the year,” Interior Secretary David Bernhardt said in an interview. The decision caps more than 30 years of efforts by oil companies and Alaskan leaders to drill in the refuge.

Environmentalists have raised concerns about the impact drilling could have on the polar bears and caribou herds that live in the remote refuge in northeast Alaska. Congress passed a mandate to lease oil rights in part of the refuge in its tax overhaul in 2017, when both the House and Senate were in Republican control.

Mr. Bernhardt said the drilling can be conducted in an environmentally sound manner and that Congress has set details into law that will help the plan withstand challenges from environmentalists.

“Congress gave us a very clear directive here, and we have to carry out that directive consistent with the directive that they gave, and consistent with the procedural statutes,” Mr. Bernhardt said. “I have a remarkable degree of confidence that this can be done in a way that is responsible, sustainable and environmentally benign.”

The refuge, often known by its acronym ANWR, is nearly the size of South Carolina, nestled between the Arctic Ocean to the north and Canada’s Yukon to the east. Congress approved protections for it in 1980, and its expansive tundra, mountains and coastal plain are still nearly void of people and roads.

Investors question its value, however, as a source of oil, especially in an era of lower crude prices and tepid demand. The industry is glutted with supply world-wide, pushing companies of all sizes to plan deep spending cuts.

The reserves in ANWR are uncertain and drilling there appears unpopular with the public. Combined with the sheer expense of entering Arctic wilderness for the first time, it might all chase away several of the major companies that could afford such a capital outlay.

Goldman Sachs Group Inc. and Wells Fargo & Co. are among several banks to rule out funding for ANWR drilling specifically, and more have broadly ruled out financing for Arctic development.

BP PLC, a pioneer of Alaska oil, decided last year to sell all of its assets in the state even with an ANWR auction pending—only to see the deal temporarily delayed this spring while falling oil prices caused major banks to balk at financing the buyer, Hilcorp Energy Co.

Financiers are concerned about climate change and low oil prices, and that is likely to keep oil companies from lining up to drill in the refuge, said Quincy Krosby, chief market strategist at Prudential Financial Inc., which manages more than $1 trillion in assets.

“Investors, with the energy companies, they don’t want a backlash from university endowments, sovereign-wealth funds and so on,” Ms. Krosby said. “But, more importantly, I go back to the economic fundamentals: Why do you have to go there for oil?…The optics at this stage don’t bode well for this sort of endeavor.”

Mr. Bernhardt reiterated the department’s assertion that oil drilling can be done in the coastal plain along the Arctic Ocean, at the northern tip of the refuge, without spoiling the area. The Interior Department says drilling pads, processing plants and roads needed for drilling will take up just 0.01% of refuge’s 19 million acres.

Pipelines that hover over the ground, however, are largely not counted toward that limit. Environmentalists contend the area should remain in a wild state, and have held out hope that drilling could be averted if Democrats gain the White House or attain a majority in the Senate.

Oil development threatens wildlife and is likely to worsen climate change, according to the Alaska Wilderness League, one of the groups that has opposed opening the Arctic refuge to drilling.

“Our climate is in crisis, oil prices are cratering, and major banks are pulling out of Arctic financing right and left,” Adam Kolton, the group’s executive director, said in a statement Monday. “This rush to drill would culminate in a fire sale of our nation’s most iconic wilderness.”

Congress gave the Interior Department until December 2021 to sell oil leases. Doing so this year, locking the government into contracts with companies, would make it harder to delay or undo the plan for drilling in the refuge even if Democrats who oppose the plan come into power, lawyers have said.

Mr. Bernhardt said all environmental laws were scrupulously followed, but he also said the department moved quickly given President Trump’s support for boosting U.S. energy production.

“We take our direction from the president. The president has been very robust on opening additional areas of federal lands, as appropriate, to resource development,” Mr. Bernhardt said. “We’ve tried to hit his priorities as expeditiously as we can—with appropriate deliberation.”

Kara Moriarty, leader of the Alaska Oil and Gas Association, emphasized that drilling is limited to the coastal plain and said production is likely 10 years to 15 years away even with a lease sale this year.

“For Alaska, having continued oil and gas development for the next 30, 40, 50 years is imperative to the state’s economy,” she said. “And, yes, there’s oil everywhere, but…we have the strongest environmental regulations. I’d put them up against any others in the world.”

Alaska has been rocked in recent years by steep drops in both production and exploration. A boom in shale drilling elsewhere has drawn drillers to easier-to-reach and less environmentally sensitive areas, and state leaders have urgently sought ways to lure them back.

When the Interior Department’s Bureau of Land Management finished its environmental impact statement on the project last year, Alaska’s congressional delegation and other state leaders urged the department to move forward quickly on leasing the refuge. Sen. Lisa Murkowski (R., Alaska) said it would “strengthen our economy, our energy security, and our long-term prosperity.”

“This is a capstone moment in our decadeslong push,” Ms. Murkowski said in a statement. “New opportunity…is needed both now, as Alaskans navigate incredibly challenging times, and well into the future as we seek a lasting economic foundation for our state.”

Mr. Bernhardt said he believes companies with a long-term vision will bid on the prospect, even with oil prices around a 15-year low.

“Under [a] long-term scenario you’re still looking at an incredibly large, conventional onshore prospect that is far less complex than many,” Mr. Bernhardt said. “And when you look at this from a world-wide standpoint, I’m very confident there will be people and entities who are very interested in this as an attractive prospect.”

His department’s environmental impact statement said the industry would have to develop new ways to find polar bears because their testing systems had never been used in a place with so many bear dens and pregnant females.

It said the potential for bear deaths and injuries “could be high,” though “the risks are generally well understood.”

Updated: 8-25-2020

Norway’s Biggest Private Money Manager Exits From Exxon, Chevron Over Climate Change

Storebrand Asset Management says it sold off more than $47 million in 21 companies.

Norway’s largest private money manager, Storebrand Asset Management, excluded and divested itself of more than two dozen listed companies under its new climate change policy, citing concerns with lobbying, coal and oil sands.

The investment firm, a unit of insurer Storebrand ASA with around $91 billion under management, said Monday it sold off more than $47 million in 21 companies and excluded another six from future investments.

Storebrand’s decision comes as more investors in Europe and abroad have called for polluting companies to align their lobbying and businesses with the Paris Agreement on climate change, with some threatening to divest.

Under its new policy, Storebrand said it would no longer invest in companies that earn more than 5% of revenue from coal or oil sands or that lobby against the Paris Agreement, among other criteria. The companies Storebrand exited from are mostly in oil and gas and the broader energy sector.

Jan Erik Saugestad, chief executive of Storebrand AM, said in an interview that the companies the firm divested itself of aren’t on track to transition to a lower-carbon economy and are too risky in the long term.

“Companies that don’t recognize climate risk or do not seize those opportunities are, in our mind, less attractive,” he said.

Big names Storebrand exited from due to their lobbying activities were U.S. oil-and-gas giants Exxon Mobil Corp. and Chevron Corp., German chemical maker BASF SE, and Australian miner Rio Tinto Ltd.

A spokesman for Exxon, which Storebrand divested itself of nearly $12.3 million, pointed to a statement from Stephen Littleton, vice president of investor relations, that was made in advance of this year’s shareholder meeting following criticism from some investors of its lobbying. Mr. Littleton said Exxon would provide more disclosures on its lobbying.

“We recognize not all shareholders will agree on the best way to manage risks, and we respect those with different perspectives and welcome their engagement,” he said in May.

A spokesman for Chevron, from which Storebrand pulled more than $10 million, said the board of the San Ramon, Calif.-based oil giant is carefully considering a shareholder resolution that would require it to disclose lobbying on climate change.

“We are not always aligned with all the views of those organizations, but it’s important for us to be part of conversations on challenging issues where there are multiple points of view,” the spokesman said.

A BASF spokesman said it wouldn’t comment on moves by shareholders, but stressed that the chemical maker “clearly supports the Paris Climate Agreement.” Storebrand pulled more than $2.7 million from the company.

A Rio Tinto spokesman also declined to comment on its shareholders, but pointed to disclosures it provides on its website regarding its lobbying. Storebrand pulled nearly $3.8 million from the mining company.

ConocoPhillips, which Storebrand divested itself of close to $4 million over its oil-sands business, declined to comment.

In Asia, Storebrand sold more than $373,000 from Taiwan Cement Corp. and more than $313,000 from Japan’s Kansai Electric Power Co., both due to their coal activities.

The companies said through spokespeople that they are working to cut their emissions and become more energy efficient, though Kansai declined to comment directly on Storebrand’s decision.

Taiwan Cement’s spokesperson said the Taipei-based company “has been striving to become a green environmental engineering company” because of advice from shareholders.

Mr. Saugestad of Storebrand said he hopes the new policy serves as an example for other investors and inspires them to follow suit.

“It’s a natural step in evolution,” Mr. Saugestad said.

Updated: 8-26-2020

Exxon’s Departure From Dow Highlights Market’s Retreat From Energy Bets

After being the largest U.S. company as recently as 2013, Exxon has been eclipsed by technology giants.

The Dow Jones Industrial Average’s coming farewell to Exxon Mobil Corp. is the latest sign of the waning influence of America’s struggling energy sector.

When trading begins next week, the blue-chip benchmark will include only one energy stock: Chevron Corp., which will represent just 2.1% of the price-weighted index, according to an S&P Dow Jones Indices analysis.

In the broader S&P 500, the group isn’t faring much better: Its weighting has shrunk to less than 2.5%, leaving energy as the least influential of the 11 represented industries. That is a dramatic fall from the end of 2011, when energy stocks accounted for 12% of the market, according to Howard Silverblatt, senior index analyst at S&P Dow Jones Indices.

Although the removal from the Dow is largely symbolic—much less money tracks the 30-stock index than follows the S&P 500—Exxon’s departure has historical significance. The company is the longest-tenured member of the benchmark, having joined in 1928 as Standard Oil of New Jersey.

It is also a reminder of Exxon’s fall from the top echelon of American industry. As recently as 2013, Exxon was the largest U.S. company with a market value above $415 billion. It has since shrunk to less than $180 billion and has been eclipsed by the technology giants such as Apple Inc., Amazon.com Inc. and Microsoft Corp. that now drive the American economy.

“Exxon, that used to be a behemoth in the U.S. markets, and now it’s dropped out of the Dow,” said Matt Hanna, portfolio manager at Summit Global Investments. “That just goes to show how quick things can change and how far energy has fallen as a sector.”

Usually, market contrarians say a sector that is so beaten down should be ripe for bargains. But many investors remain skeptical of an energy rebound, pointing to muted expectations for global growth and spotty earnings.

Energy is by far the worst-performing S&P 500 sector this year, down 40% while the index as a whole has gained 6.6%. The underperformance is nothing new: Energy was also the weakest performer in 2018 and 2019.

The fortunes of energy stocks are closely tied to oil prices, which plunged this year when the coronavirus pandemic sapped demand for fossil fuels as producers were already struggling to manage a glut of oil and gas. U.S. crude has dropped nearly 30% in 2020 and is hovering just above $40 a barrel.

Subdued expectations for economic growth and increased interest in renewable energy have all contributed to the sector’s decline.

Energy stocks are unpopular among fund managers. The net share of respondents to August’s BofA Global Fund Manager Survey who were underweight energy was the most of any sector.

“It’s very difficult for Exxon to really grow when you have low economic growth, muted commodity prices and we’re going to be transitioning away from that main line of business into something else,” said Mr. Hanna, who said his firm holds no energy stocks in its large-cap portfolio. “With the expectation that we’re moving away from oil, that makes a company like Exxon or the energy complex overall just not as interesting to a lot of investors.”

Exxon shares are off 41% this year, while Chevron is down 29%. The pain is even more acute among some of the oil-field services companies and shale drillers. Schlumberger has dropped 52%, and EOG Resources Inc. has fallen 47%. Only one company in the S&P 500’s energy sector, Cabot Oil & Gas Corp., is up for the year.

Exxon last month posted a quarterly loss for the second straight quarter for the first time in more than 20 years. The company has slashed its capital-spending plans to better manage its expenses during the pandemic. Oil companies have moved to bolster their finances in recent months, cutting tens of billions of dollars from their budgets and laying off thousands of employees.

Oil companies were struggling to attract investors even before the pandemic amid concerns over climate-change regulations and increasing competition from renewable energy. Exxon has sought to retain investors by paying a hefty dividend, but some analysts have questioned whether the company will be able to maintain the payout if energy demand doesn’t improve.

The company played down the significance of its removal from the Dow.

“This action does not affect our business nor the long-term fundamentals that support our strategy,” spokesman Casey Norton said in an email. “Our portfolio is the strongest it has been in more than two decades, and our focus remains on creating shareholder value by responsibly meeting the world’s energy needs.”

S&P Dow Jones Indices, which manages the 30-stock benchmark, said Monday that the changes to index were prompted by Apple’s planned 4-to-1 stock split. Along with Exxon, Pfizer Inc. and Raytheon Technologies Corp. are departing the index, while Salesforce.com Inc., Honeywell International Inc. and Amgen Inc. are joining it.

Apple’s stock split would have given the information-technology sector a smaller representation in the index, and the changes will help mitigate Apple’s decision. The moves “help diversify the index by removing overlap between companies of similar scope and adding new types of businesses that better reflect the American economy,” S&P Dow Jones Indices said.

Component stocks of the Dow are selected by the index committee, a group that includes editors of The Wall Street Journal, which is published by Dow Jones & Co., a part of News Corp.

Although Chevron has historically been smaller than Exxon, the gap in their market caps has been narrowing. It stood at about $13 billion on Tuesday and had been as slim as $4.6 billion in March, according to Dow Jones Market Data. Chevron’s pending $5 billion deal to buy Noble Energy Inc., an independent oil-and-gas producer, will further narrow the divide.

In a research note Tuesday, Goldman Sachs Group Inc. analysts attributed Chevron’s outperformance relative to Exxon to a stronger balance sheet and better earnings execution, among other factors.

Perhaps more important for the price-weighted Dow, Chevron’s stock price is higher. It currently trades above $85 a share, while Exxon is around $40. The only companies in the index with lower share prices are Walgreens Boots Alliance Inc. and Pfizer, which is also set to be removed next week.

Chevron is in the midst of its third appearance in the Dow. It was part of the index as Standard Oil Co. of California from February 1924 to August 1925. The company rejoined in 1930, was replaced in 1999 and returned again in 2008. Both Exxon and Chevron are descendants of Standard Oil Co., which was forced to break up in 1911.

In recent years, investors have been compensated for ignoring the energy sector, said Mark Stoeckle, chief executive and senior portfolio manager at Adams Funds, which manages a natural-resources fund. But because of energy’s importance to the economy, he said having some exposure makes sense.

“Nobody knows when the marketplace is going to all of a sudden begin to reward these companies,” he said. “I don’t think these companies are going to zero.”

Updated: 9-1-2020

Summer Fuel Demand Disappoints, Challenging Economy

Oil prices stay in tight range as coronavirus fears fuel caution among consumers.

A swift recovery in fuel consumption by U.S. drivers is petering out, posing new challenges to the oil market, economy and global energy industry.

After demand for gasoline surged from mid-April to late June, consumption has stayed relatively flat in the past two months and remains well below its prepandemic levels, government data show. The fizzling rebound highlights the lingering effects of coronavirus precautions and travel restrictions. Even as some states advance business-reopening plans, rising cases in other parts of the country are fueling caution among consumers.

Many companies have delayed plans to reopen offices, while many school districts and colleges around the country are opening with hybrid or remote instruction, taking a bigger bite out of fuel demand.

Combined with other data points showing that improvements in consumer spending and hiring are cooling, the slower increase in fuel demand illustrates that the next phase of the economic recovery could be more difficult.

The trend is a threat to the economy because people tend to spend more money when they are moving around and engaging with businesses. Some analysts think gasoline demand will need to rise for the economic recovery to continue at its current pace, especially with many Americans avoiding public transportation because of coronavirus concerns and seeking to take vacations before summer ends.

The stalled demand rebound is helping keep U.S. crude-oil prices stuck in the low $40s per barrel, even with the Organization of the Petroleum Exporting Countries and companies from Exxon Mobil Corp. to Chevron Corp. curbing supply in response to the industry turmoil.

Oil has remained in a narrow trading range for two months following a swift rebound after prices in April briefly dropped below $0 for the first time.

As a result, fuel prices also have remained flat recently, a boon for those consumers who are able to take advantage at the pump but a threat to energy companies whose spending cuts and layoffs could add to the pressure on the economy.

“The easy work has been done,” said Noah Barrett, an energy analyst for Janus Henderson Investors. “That last 10% to 15% of lost demand is going to be really hard to get back.” He is cautious about the oil-price recovery because of the questions about demand.

U.S. motor gasoline supplied by energy companies, a proxy for demand, stayed at roughly 8.6 million barrels a day for two months through mid-August before jumping to 9.2 million barrels a day during the week ended Aug. 21, according to the Energy Information Administration.

That is up from a low in April around 5 million barrels a day but well below the figure of 9.7 million barrels a day from mid-March, before lockdowns took hold in much of the country.

It also is below last summer’s driving-season peak of close to 10 million barrels a day. Demand for distillate fuel including diesel has followed a similar pattern, while consumption of jet fuel is still weak with air travel limited.

“We are at this tenuous point where prices have recovered nicely from the abyss we were in a few months ago but are still at very challenging levels for the industry,” said Jennifer Rowland, senior energy analyst for Edward Jones.

Investors say that unless demand picks up, even more energy companies will be forced to file for bankruptcy or pursue mergers and acquisitions in the months ahead.

More than 30 North American energy exploration-and-production companies filed for bankruptcy in the first seven months of the year, according to law firm Haynes and Boone. Consulting firm Rystad Energy projects that about 150 more will seek chapter 11 bankruptcy protection through 2022 without higher prices.

“The whole industry is reeling,” said Regina Mayor, who leads KPMG’s energy practice. “It will take through the end of 2021 at the earliest to fully see anything like what we had in 2019 for fuel demand.”

Shares of energy producers have fallen 25% from a peak hit in early June. The energy sector is lagging behind even as gains in technology shares power the S&P 500 to records.

The demand uncertainty is forcing producers to remain cautious with drilling new rigs and denting profits for refiners that turn oil into fuel.

“We’re seeing a slow recovery, which is headed in the right direction, but we’re just anticipating that it could take a while to get back to normal,” Michael Hennigan, chief executive of refiner Marathon Petroleum Corp., said on the company’s most recent earnings call last month. Marathon and other refiners such as Phillips 66 and Valero Energy Corp. are processing less crude and limiting spending.

Marathon last month agreed to sell its gas stations to the owners of the 7-Eleven convenience-store chain for $21 billion.

In a reminder of the energy industry’s waning influence on financial markets, Exxon was replaced Monday in the blue-chip Dow Jones Industrial Average. Chevron remains in the 30-member stock index.

“It’s emblematic of the struggles that the energy sector has faced,” Janus Henderson’s Mr. Barrett said of the change. “The lack of interest in owning a lot of these stocks is still pretty high.”

Updated: 9-2-2020

Saudi Aramco Slows Diversification Plans Amid Industry Downturn

The world’s biggest oil producer is pausing commitments to invest in natural gas and petrochemicals.

Saudi Arabia’s state oil giant is reviewing plans to expand at home and abroad in the face of sharply lower oil prices and a heavy dividend burden it assumed as part of its recent initial public offering, according to people familiar with the matter.

Saudi Aramco is now slowing down and reviewing a $6.6 billion plan to add petrochemical output at its Motiva refinery in Texas, these people said. It is also reviewing a big natural-gas project with Sempra Energy in the same state, and pausing investments in refineries in China, India and Pakistan, these people said.

At home, Aramco is delaying by a year plans, announced in March, to boost crude production capacity to 13 million barrels a day, from currently about 12 million, these people said.

Aramco didn’t immediately return requests for comment.

In its December IPO, Dhahran-based Saudi Arabian Oil Co. promised shareholders $75 billion in annual dividends for the next five years. That pledge helped persuade private investors to pay a premium for the thin slice of Aramco shares the government floated on the local stock market.

Other big oil companies, such as Royal Dutch Shell PLC and BP PLC, have cut their dividend in recent months to preserve cash, amid sharply falling oil demand and prices thanks to the pandemic.

Aramco’s flexibility to do the same is limited because the Saudi Arabian government—which still owns 98% of the company—relies on Aramco dividends for much of its funding.

Last month, Aramco said it would maintain its quarterly dividend at $18.75 billion, dwarfing free cash flow of $6.1 billion for the period. That was down from $20.6 billion a year earlier, when oil prices were higher.

It also reported a 73% fall in net profit in the second quarter and said it would cut capital expenditures by about half, to between $20 billion and $25 billion. The spending will target domestic crude production, it said.

That is a sizable turnaround from two years ago. At the time, Aramco laid out plans to invest $100 billion in chemical manufacturing, and unveiled a separate ambition to buy as much as $160 billion in natural gas assets.

The company said it wanted to become a competitor in the global natural-gas market and also balance its giant oil-production capacity with the ability to process crude into other products—a diversification strategy employed by most of the world’s biggest oil companies.

As part of this push, Aramco paid $69 billion to buy a controlling stake in Saudi Basic Industries Corp., or Sabic, the kingdom’s biggest petrochemicals company. It also paid $1.2 billion for a stake in South Korean refiner Hyundai Oilbank in December. The Sabic deal sharply expanded debt at Aramco after it consolidated the petrochemical company’s liabilities.

Net debt as a percentage of total capital, a closely watched industry metric, jumped to 20% at Aramco in the just-ended second quarter. The company’s target range is between 5% and 15%.

Amid that new financial pressure, billions of dollars worth of planned investment are now being delayed and reviewed and, in some cases, are unlikely to proceed, according to the people familiar with the matter.

Those holdups include a $20 billion refining and petrochemical complex in Yanbu, on Saudi Arabia’s western coast, the people said. The project was supposed to get the green light late last year, with the project startup slated for 2025. Now, those plans are being reviewed, according to the people familiar with the matter.

Also on pause is the expansion plan for the company’s Motiva refinery in Texas, these people said. It had planned to spend $4.7 billion to build capacity to produce ethylene and a further $1.9 billion to produce benzene and paraxylene.

That represents the second delay to the expansion, after Aramco pushed back a final investment decision for the project last year. Aramco is now also considering whether to go ahead at all with the expansion, according to these people.

A deal with San Diego-based Sempra Energy is on hold, too, according to these people. Aramco agreed to buy 20 years worth of liquefied natural gas from a Sempra-led project planned for Port Arthur, Texas. Aramco also agreed to take a 25% equity stake in the project’s first production phase.

The deal was characterized as a first step in a much bigger plan to snap up natural-gas assets. That first phase is now delayed until at least next year and the entire investment is being reviewed, according to people familiar with the matter.

Sempra said a final investment decision on the project is now expected in 2021, delayed from this year, but that “the agreement remains in effect and we continue to work with Aramco.”

Aramco is also delaying plans to invest in refineries in Pakistan and India, these people said, and has also suspended a deal to build a $10-billion refining and petrochemicals complex in China’s Northeastern province of Liaoning. The delay was first reported by Bloomberg last month.

At the time it entered that agreement, Aramco also said it planned to acquire a stake in a refining and petrochemical complex in the eastern Chinese city of Zhoushan. This plan remains intact and a priority for Aramco, according to the people familiar with the matter.

One other investment still likely to go ahead is Aramco’s planned purchase of a big stake in Indian conglomerate Reliance Industries’ oil-to-chemicals business, the people said.

Aramco views an investment in India as a long-term strategic move, given it is a market with growing energy demand, these people said. Last month, Aramco Chief Executive Amin Nasser said a final decision on the investment is pending.

Updated: 9-2-2020

Hilton Hotel In Times Square Is Set To Close

Property will lay off 200 workers, the latest sign that New York City’s hospitality industry is struggling to survive during the coronavirus pandemic.

The Hilton Times Square is set to become one of the most prominent Manhattan hotels to shut down on a long-term basis amid the coronavirus pandemic.

In a Monday public filing with the New York State Department of Labor, the company in control of the 478-room hotel announced the “permanent closing” of the property and said it would cut 200 jobs, effective in October.

A spokesman for Sunstone Hotel Investors Inc., which controls the hotel, said in an email the company made the filing to indicate that layoffs might last longer than six months. He said the filing “was not intended to imply that there is a permanent closure.”

He added that a “definitive reopening date has not been determined or established and will be impacted by negotiations with our lender, as well as market conditions.”

The hotel, which is a franchised property under the Hilton Hotels & Resorts brand, closed to visitors in March and began furloughing workers.

The closure is the latest sign of how the pandemic and recession have upended the once-mighty New York City hotel industry as tourists stay home and business travel is virtually shut down.

A number of hotels have temporarily closed their doors and furloughed or laid off workers, and the Hilton Times Square is one of the first to publicly say it won’t reopen for the indefinite future.

Times Square’s hotels are particularly dependent on overseas travel, which has all but dried up because of the pandemic, and Broadway shows, which are canceled for now. The neighborhood has seen a handful of mortgage defaults over the past year and some hotels have been partially converted into homeless shelters to make up for falling demand from tourists.

The Hilton Times Square has been under unique financial pressure. Sunstone, which controls the property under a ground-lease arrangement, has a $77.2 million mortgage coming due in November.

The company this year wrote down the value of the property by $107.9 million, to $61.3 million. Sunstone said in an August public filing that it hasn’t made mortgage payments since April and is in discussions with its lenders about possible solutions, which include handing over the property.

Meanwhile the ground rent, which Sunstone pays to the owner of the land under the building, was set to rise considerably in May. The company said in the filing that it hasn’t paid ground rent since March, received a default notice from its landlord and is in negotiations over the lease deal.

Manhattan’s hotel market was already under pressure from rising operating costs and an oversupply of rooms when the pandemic led to a sudden drop in bookings starting in March.

New York City’s hotel-occupancy rate fell to just 19.6% in early April, according to data firm STR, although it has since regained some ground. Some analysts predict that as many as 25,000 New York hotel rooms might never reopen.

Updated: 9-14-2020

Exxon Used To Be America’s Most Valuable Company. What Happened?

The oil giant doubled down on oil and gas before the pandemic crushed demand.

It has been a stunning fall from grace for Exxon Mobil Corp.

Just seven years ago, Exxon was the biggest U.S. company by market capitalization. It has since lost roughly 60% of its value, with its market cap now at around $160 billion, after the pandemic crushed demand for fossil fuels.

Analysts estimate Exxon will lose more than $1 billion this year, compared with profits of $46 billion in 2008, then a record by an American corporation. The company’s removal from the Dow Jones Industrial Average in late August, after nearly a century on the index, marked a milestone in its decline.

At the heart of the problem: Exxon doubled down on oil and gas at what now looks to be the worst possible time. While rivals have begun to pivot to renewable energy, it is standing pat. Investors are fleeing and workers are grumbling about the direction of a company some see as out of touch and stubborn.

Two years ago, Chief Executive Darren Woods unveiled an ambitious plan to spend $230 billion to pump an additional one million barrels of oil and gas a day by 2025. So far, production is up slightly since 2018, but the added spending has weighed down the company, which recently posted two consecutive quarterly losses for the first time in more than 20 years.

xxon believes the world’s growing population will need fossil fuels for decades to come and that the company’s bet on additional production will yield profits in the long run. Oil demand has stalled during the pandemic, but it has been rising for much of the past century.

Exxon’s bets could pay off in the long term if oil and gas prices go up later this decade and rivals’ lack of investment leaves them unable to capitalize. The company disputed there is discord within its ranks over its direction.

To address risks posed by climate change, it says it is investing in new technologies, including those that capture carbon from the atmosphere or reduce methane emissions, which may help reduce the impact of fossil fuels on the climate.

“Our portfolio is the strongest it has been in more than two decades, and our focus remains on creating shareholder value by responsibly meeting the world’s energy needs,” said Exxon spokesman Casey Norton.

The Irving, Texas, company has shed $10 billion or 30% from this year’s capital expenditures, and slowed projects from West Texas to Africa.

Dividends are one reason investors stick with oil companies. Exxon has had to take on debt to cover its hefty payouts and some analysts forecast that they may not be sustainable.

Exxon has promised not to cut the payouts, as rivals including Royal Dutch Shell PLC and BP PLC have done, or take on additional debt. That has concerned some investors.

“It’s one thing to have a lot of confidence and bravado, as Exxon has for years, but when things start getting as tight as they are now, and they are tight, how can you not change your stripes,” said Mark Stoeckle, chief executive of Adams Funds, which owns 1.6 million Exxon shares.

Rivals such as Shell and BP have also begun investing in renewable energy. In March, Mr. Woods dismissed targets set by those companies and others to reduce carbon emissions as a “beauty competition.”

Some employees across the company’s operations say its style of management is no longer working in the face of new threats such as climate-change regulations and competition from renewable energy, according to interviews with more than 20 current and former employees.

“While much of your focus has been on a small number of employees who have left the company, we’re proud of our 74,000 employees around the world who continue to work hard during the ongoing global pandemic, making significant contributions to [the] company’s ongoing efforts to be a market leader,” the company said in a written statement.

While other major oil producers have announced more than 35,000 layoffs, Exxon has, so far, announced none. Exxon is suspending matching contributions to U.S. employees’ retirement plans starting in October and is conducting a workforce review that may lead to layoffs.

Employees say changes in the company’s internal ranking system could mean that thousands of workers are already quietly on the chopping block.

Exxon uses a ranking system to grade employees relative to their peers. It recently changed its formula, increasing the number of U.S.-based employees deemed to need “significant improvement” from at least 3% to between 8% to 10%, according to documents dated April 2020 that outlined the changes.

Employees with low rankings must choose between leaving the company with three months of pay, or entering a three-month probationary period during which they have to meet management targets or be fired.

Mr. Norton, the Exxon spokesman, said, “We do not have a target to reduce headcount through our talent management process.” He added that the company is conducting a comprehensive review of potential cost reductions that could lead to fewer managerial roles.

Enrique Rosero, a former Exxon geoscientist who left the company this summer after receiving a low ranking, said he was punished for asking questions about the company’s climate strategy. Mr. Rosero was ranked among the top third of Exxon’s employees two years ago, according to a document viewed by the Journal, and said he was told by his supervisor in April that he would receive an excellent review this year.

During a town hall meeting that month with senior executives, Mr. Rosero said he asked whether Exxon’s acknowledgment that fossil fuels contributed to climate change was inconsistent with its corporate strategy. Several other employees said Mr. Rosero had previously pressed management on such issues.

“We acknowledge the need to reduce our emissions, yet they are set to increase by at least 20% over the next five years,” Mr. Rosero said during the meeting, according to Mr. Rosero and several other people who were present. “In the end, wouldn’t you agree that this is a problem of behaviors and leadership?”

Tolu Ewherido, a vice president in Exxon’s oil and gas production business, responded, “I don’t hear a question in there,” according to Mr. Rosero and the others present.

Mr. Rosero said his supervisor told him in May that the exchange had come up in a meeting and would negatively impact his employee ranking.

In July, his supervisor told him he ranked among the bottom 10% and was given the choice of taking a three-month probationary period or 90 days’ pay. He took the pay and left the company on July 21.

Mr. Norton declined to specifically address Mr. Rosero, but said Exxon’s review process is fair and based on annual expectations, achievements and patterns of behavior. The number of workers in the “needs significant improvement” category under the company’s ranking system is adjusted on an annual basis and “has been as high as 10 percent in prior years,” he said.

“We encourage an open dialogue and we do not tolerate retaliation,” Mr. Norton said.

Bad Bets

Exxon—the largest direct descendant of John D. Rockefeller’s Standard Oil monopoly—has struggled through a period of relatively low oil prices for years due to an abundance of oil and gas unleashed by U.S. frackers. After missing out on the beginning of the shale boom, Mr. Woods’ predecessor, Rex Tillerson, bet big on projects around the world that mostly failed to meet expectations.

Between 2009 and 2019, Exxon spent $261 billion on capital expenditures, while its oil and gas production remained flat, and it added $45 billion in debt, according to investment bank Evercore ISI. Its return on capital employed in 2009 was 16%; last year it was 4%.

To get into the shale business, Exxon bought XTO Energy Inc. for more than $30 billion in 2010, when natural gas prices were higher than they would be for most of the next decade. Large and risky investments in the Russian Arctic and Canadian oil sands haven’t gone as planned.

To reverse Exxon’s fortunes, Mr. Woods returned to the company’s playbook: investing heavily in mega-projects during a period of low oil prices to catch the upswing. It has spent billions in Guyana and the Permian Basin.

Even before the pandemic, some of Exxon’s growth plans in Texas were viewed as unrealistic by some workers, according to current and former employees.

In March 2019, Exxon said it would increase oil and gas production in the Permian Basin to 1 million barrels per day as early as 2024, up from previous estimates of 600,000 by 2025. Some staff assigned to the project thought that was overly optimistic, said six current and former employees.

For one area called the Delaware, some Exxon managers in 2018 had initially pegged the net present value of those holdings at about $60 billion, according to several employees.

Some involved in the project estimated last summer that the area’s net present value was closer to $40 billion because they believed Exxon was overestimating how quickly it could drill, according to the people. After additional debate and consultation, the value was adjusted to about $50 billion, said the people.

Exxon disputed there had been a significant disagreement over the valuation. The company’s “annual planning process considers multiple inputs from multiple working groups across a wide range of complex technical areas,” and it is often the case that some experts and managers initially have different views, it said.

In response to the pandemic, Exxon has cut spending in the Permian and lowered its production estimates in 2020 to around 345,000 barrels per day. Prior to that, it was on track to meet or surpass its long-term growth goals there, it added.

“We reject the claims made by your sources who, based on their comments, have an inaccurate, incomplete and dated perspective of resource and development plans,” Exxon said in a statement, saying it exceeded the 2019 plans. “Actual performance has proven that their position is inaccurate.”

Fossil Fuels

While rivals such as Shell and BP have begun hedging their oil and gas bets with investments in renewable energy, Exxon has remained largely committed to fossil fuels.

In the 1960s, Exxon created an in-house venture-capital division that helped develop some of the first commercially viable solar cells before selling the unit in the 1980s, determining oil and gas were more profitable. Several employees said the company has chosen to primarily innovate on oil- and gas-related technology.

“ExxonMobil is a world leader in carbon capture,” the company said.

Mr. Woods has said Exxon is investing in groundbreaking technology, including algae biofuels and capturing carbon. He has also emphasized company traditions, including its employee-ranking system, that he believes have made Exxon successful.

In early 2018, around the time he laid out his growth plan, Mr. Woods visited the company’s flagship Houston-area campus for a town hall meeting. He spoke to more than 1,000 employees in the campus’ main building, which features a 10,000-ton “floating cube” that appears to hover over a plaza below.

When the meeting shifted to a question-and-answer session, some employees asked about the ranking system and whether Exxon would ever get rid of it, said six people who attended. Many large companies have abandoned such rankings, including Microsoft Corp. and General Electric Co., which pioneered the system in the 1980s.

Mr. Woods appeared annoyed by the question and said Exxon would never get rid of the rankings, according to the people.

“We need to win in the marketplace,” Mr. Woods said, according to the people.

Updated: 9-14-2020

OPEC Extends Forecast For Decline In Global Oil Demand

In its monthly report, cartel said it expects the pandemic to reduce demand by 9.5 million barrels a day.

The economic hit from the coronavirus pandemic will hurt global energy demand harder and for longer than previously feared, the Organization of the Petroleum Exporting Countries said Monday.

In its monthly report, OPEC said it expects the pandemic to reduce demand by 9.5 million barrels a day, forecasting a fall in demand of 9.5% from last year.

In further signals of the gloom, the cartel softened the amount by which it expects non-OPEC oil supply to fall this year—in part because of a recovery in U.S. output—and blunted its demand recovery forecast for next year. That was accompanied by a sharper forecast hit to the global economy: OPEC now expects a 4.1% contraction in activity.

Oil prices slipped on Monday, with Brent crude oil, the global benchmark, down 0.5% at $39.62 a barrel. West Texas Intermediate futures, the U.S. benchmark, were down 0.5% at $37.14 a barrel, with investors concerned about reports that Libyan supply may soon return to the market and that Emirati compliance with production cuts has dropped, said Eugen Weinberg, head of commodities research at Commerzbank.

The price of crude has fallen by double-digit percentages in September, with weaker-than-expected demand metrics, price cuts from major producers and economic jitters combining to shock prices out of their summer torpor.

OPEC repeatedly slashed its oil demand forecast as the coronavirus hammered the global economy during the spring, before muting its most doom-laden estimates during the summer. Monday’s cut marked the second straight month in which the cartel reduced its demand forecast, a signal of the growing concern about a second spike in Covid-19 cases and a stalling recovery in oil demand.

The Vienna-based organization cited slowing economic activity, a slower-than-anticipated recovery in transportation fuel demand, and rising coronavirus cases in India, Indonesia, Thailand and the Philippines as playing a large part in its latest forecast cut.

Monday’s report comes ahead of the meeting of OPEC’s joint ministerial monitoring committee Thursday, at which the cartel and its allies will discuss plans to further relax production curbs in the coming months.

While there are few signs that the OPEC+ alliance is looking to adjust those plans this month, “the impact of Covid-19 related developments on already fragile global economic conditions remain[s] challenging and will require coordinated global policy action from all market participants,” OPEC said in its release.

Saudi, Emirati and Kuwaiti production rose as part of the OPEC+ plan to relax cuts.

Meanwhile, the recovery in global refinery margins seen in July faltered during August, with European margins hitting record-breaking lows and barely remaining positive, OPEC said.

Updated: 9-17-2020

Oil Producers’ Best Customers Are In Trouble

Oil-demand forecasts keep getting cut; source of those reductions should be cause for concern.

Oil-producing nations have shown remarkable discipline so far in making sure the global supply will be somewhat predictable. Demand, however, is proving much more elusive.

After forecasting a global recovery, both the International Energy Agency and the Organization of the Petroleum Exporting Countries cut their outlook in August and then even further down in reports released this week. OPEC’s latest projection is the most bearish it has been so far this year: It is expecting 9.5 million barrels a day less compared with last year.

What is concerning isn’t just the direction of their latest revisions but where the oil-demand weakness is coming from: Emerging markets—those that aren’t part of the Organization for Economic Cooperation and Development—were responsible for the latest downward revisions.

That is a troubling sign because emerging economies are crucial to oil-demand growth. They have represented the largest share of oil demand since 2012, reaching 53% in 2018, according to the IEA.

Adding to the concern is the fact that non-OECD countries’ oil consumption is still strongly linked to their gross domestic product, according to data from the U.S. Energy Information Administration and Oxford Economics. Unlike OECD countries, a greater proportion of their economies are in manufacturing industries.

It will take much more than resuming travel to resuscitate oil demand, and those countries have much less in their fiscal toolbox to help them do so. In fact, the World Bank projects that many of these countries’ economies will be operating well below their potential even five years from now.

Take India, the third largest consumer of oil and the strongest contender to overtake China’s oil-demand growth in future years. In the second quarter, its economy registered its sharpest contraction in decades of almost 24% year over year as the country implemented a strict lockdown, according to OPEC. Manufacturing recorded an even worse drop of 39%, its biggest decline on record.

The demand picture looks even tougher to gauge as the weather cools. Forecasting oil demand this year is partly an exercise in predicting where the coronavirus will flare up again in the world, a seemingly impossible task. Australia, New Zealand and South Korea are all examples of countries that seemed to have a handle on the situation in June but saw significant outbreaks since.

Much damage has been done to global oil demand this year. Continued weakness from emerging markets could dent expectations for years to come.

Updated: 9-22-2020

America’s Top Oil Field Was Desperate For Pipelines. Now It Has Too Many

Permian Basin has become a headache for pipeline operators, with the pandemic further damping demand for crude.

America’s hottest oil region has too many pipelines and not enough oil to fill them, bad news for pipeline operators.

Just two years ago, rapid production growth in the Permian Basin of Texas and New Mexico had overwhelmed regional infrastructure, causing bottlenecks that crushed local crude prices.

Now, the region, which is producing around four million barrels a day of oil, has some three million barrels a day of excess pipeline space, according to East Daley Capital Advisors Inc., an energy data firm. A drop in oil demand during the pandemic, which caused crude prices to fall and forced companies to trim production, has exacerbated what was already becoming a mismatch.

The abundance of conduits is a welcome change for shale companies but challenging for fuel makers and pipeline operators such as Plains All American Pipeline LP and Energy Transfer LP that had benefited from the congestion.

“We are going to need significant consolidation in the midstream space overall, and particularly in these basins where the oversupply is as dramatic as it is,” Tyler Rosenlicht, a portfolio manager at investment firm Cohen & Steers Inc., said of the pipeline companies.

Oil fields often yo-yo between not having enough pipelines to move their crude to market and having too many. But the mismatch between pipeline space and oil output in the Permian is particularly extreme. As of September, large Permian conduits and local refineries could absorb roughly 7.3 million barrels of oil a day, according to East Daley.

By early next year, capacity is expected to climb to around 8.3 million barrels a day, meaning producers would be using only about half of the available pipeline space for Permian crude, East Daley estimates. That is down from utilization as high as around 96% in the spring of 2018.

Permian production has fallen by about 700,000 barrels a day since March, or roughly 14%, according to U.S. Energy Information Administration estimates. Covid-19 has sapped oil demand and sent U.S. benchmark prices tumbling to around $39 a barrel as of Monday.

Yet the region likely was going to have more pipelines than it needed even without the pandemic. That is because producers already were beginning to slow production as investors pressured them to prioritize returns over growth.

Last year, pipeline firms Energy Transfer and Epic Midstream Holdings LP responded by lowering some of the rates they charge to ship oil, according to East Daley.

Companies also have discussed reversing the direction oil flows on their pipes to send more oil to Gulf Coast export markets, or converting oil conduits to ones that carry natural gas or natural-gas liquids, according to people familiar with the matter.

Meanwhile, Enterprise Products Partners LP said this month that it had canceled a 450,000-barrel-a-day pipeline it was planning to build from the Permian to South Texas and renegotiated agreements with some customers.

“In the medium-term, we don’t need it, and they don’t need it,” Jim Teague, co-chief executive of the company’s general partner, said at a recent conference.

Enterprise also has considered switching one of its Texas pipelines back to handling natural-gas liquids, after having converted it to crude early last year to satisfy the crush of Permian demand. A spokesman said Monday that the company had yet to decide whether to pursue the conversion.

With little incentive to put more conduits in the ground, pipeline companies are likely to merge with one another, Plains All American Pipeline Chief Executive Willie Chiang told investors earlier this month.

“You have to grow in different ways,” Mr. Chiang said. “And I do think as we go forward more consolidation will happen.”

The abundance of pipeline capacity is yet another headwind for fuel makers, which often benefit when congestion depresses regional crude prices, allowing them to scoop up oil for processing on the cheap in specific areas.

Two years ago, Permian oil was discounted by as much as around $18 a barrel below the U.S. benchmark, according to energy-information provider Argus Media Ltd. That helped drive fuel makers including Phillips 66 and Delek US Holdings Inc. to their highest annual profit on record.

As of mid-September, oil sold in Midland, Texas, at the heart of the basin, fetched slightly more than crude traded at the Cushing, Okla., hub, Argus data show.

Shale producers, on the other hand, are reaping the benefits of abundant pipeline space, particularly ones that didn’t sign long-term contracts to ship their oil at a fixed rate.

“Two years ago, we were just looking for any way out,” said Suzie Boyd, president of Midland-based Caballo Loco Midstream LLC, which helps producers sell their oil and gas. Now, her clients have options.

“If anything, I have more stroke with the markets that I’m directing barrels to,” she said. “They’re calling me, instead of me calling them begging.”

Updated: 9-28-2020

Shale Producers Devon Energy, WPX Energy Announce Merger

Executives say deal positions companies to focus on returns, scrap prior shale growth model.

Devon Energy Corp.  and WPX Energy Inc.  have agreed to an all-stock merger that would create one of the biggest U.S. shale producers, the companies said Monday.

The combined entity’s estimated market value of about $6 billion would exceed the current value of all but seven other independent U.S. energy producers, according to data collected by RBC Capital Markets. The Wall Street Journal on Saturday reported that the companies were in talks to merge.

The deal could help the two companies ride out the oil-market slump coming after the coronavirus pandemic crippled global demand, leading American frackers to cut spending dramatically. U.S. benchmark oil prices are hovering around $40 a barrel, a level at which most shale producers can’t produce profitably—and bankruptcy looms over many weaker companies if the slump persists.

Devon Chief Executive Dave Hager said the move will accelerate plans to ditch the shale industry’s old strategy of pursuing rapid production growth at all costs and focus instead on generating income that exceeds drilling expense and returning excess cash to shareholders,

Mr. Hager will serve as the executive chairman of the combined company, which will be called Devon Energy, with Richard Muncrief, WPX’s chairman and chief executive, serving as its president and CEO.

“Investors have been vocal in advocating for responsible consolidation in our industry,” Mr. Hager said on a conference call.

Even before the pandemic, investors were generally avoiding the shale industry as most companies generated lackluster returns and spent more money than they made from drilling wells and pumping oil and gas. Collectively, 32 U.S. shale drillers outspent their cash flow in all but three quarters since the start of 2014, according to the consulting firm Rystad Energy.

Mr. Hager vowed the combined company would keep investment rates at 70% to 80% of operating cash flow and limit output growth to 5%, even in a more favorable oil-price environment. In addition to a fixed dividend, it also plans to implement a quarterly variable dividend that would distribute some of its available cash to shareholders.

Mr. Muncrief said the company would target 5% growth in oil production if prices were above $50 a barrel. “Longer term, if you’ve had a more constructive environment and you felt very confident that the higher prices were here to stay, then we could adjust accordingly,” he said.

Under the merger agreement, WPX shareholders receive 0.5165 shares of Devon for each share of WPX common stock owned. Devon shareholders would own about 57% of the combined entity, and WPX shareholders about 43%, the companies said. The enterprise value for the combined entity would be about $12 billion, they said.

Together, the companies would produce about 277,000 barrels of oil a day, with most of that coming from 400,000 net acres in the Delaware Basin, the western part of the nation’s largest oil-producing region in West Texas and New Mexico. They said the cost savings under way in the second half of the year and those resulting from the merger are expected to improve annual cash flow by $575 million by the end of 2021.

The deal is expected to close in the first quarter of 2021, the companies said. They said funds managed by EnCap Investments LP, which own about 27% of WPX shares outstanding, have supported the agreement.

Updated: 9-30-2020

Shell To Cut Up To 9,000 Jobs

Energy giant warns of another tough quarter as the pandemic continues to sap demand for oil.

Royal Dutch Shell PLC said it would cut up to 9,000 jobs in a broad restructuring, as the energy giant grapples with the continuing fallout of the coronavirus pandemic.

News of the cuts came Wednesday as the company warned it would report another set of poor earnings for the third quarter. Shell flagged a weaker performance in its trading activities—previously a bright spot in an otherwise tough second quarter—and said its oil-and-gas production business would report a second consecutive quarterly loss.

The update from Shell gives a first glimpse at how the world’s biggest oil companies have continued to struggle in the most recent quarter. The pandemic has sapped demand for oil, sending prices tumbling and hitting profits hard. That has already prompted Shell to write down the value of some of its assets and cut its dividend for the first time since World War II.

Shell said it was restructuring to focus more on the highest value oil it produces, grow in liquefied-natural gas and invest in low carbon energy businesses, while shrinking its refining operations. It expects the plan to deliver annual cost savings of $2 billion to $2.5 billion by the end of 2022, including from the staff cuts, less travel and fewer contractors.

It expects to cut between 7,000 and 9,000 jobs from its more than 80,000 employees.

The planned job cuts follow similar moves at peers including BP PLC and Chevron Corp. to rein in costs amid the pandemic.

Shell said its restructuring isn’t just a response to the pandemic, but also part of a broader plan to accelerate investments in low-carbon energy.

The company says that by 2050 it will sell predominantly low-carbon electricity, biofuels, hydrogen and other solutions. However, it says it needs its oil-and-gas business to perform well to fund that change.

Chief Executive Ben Van Beurden said Shell’s core business would be critical to the effort. “We need it to be very successful, so we have the financial strength to invest further in our lower-carbon products,” he added.

Shell is expected to update its strategy early next year, including giving details on its future spending on low-carbon energy.

BP earlier this year announced the most aggressive plan so far by an oil major to shift away from oil and gas—cutting its production by 40% in the next decade—while expanding in areas including wind and solar energy.

Detailing its performance in the third quarter, Shell said its LNG business would report lower margins, as long-term contracts started to reflect lower oil prices. It also said refining activity fell, although it noted an improvement at its oil product marketing business compared with the previous quarter.

Analysts said the update was in line with expectations and that they hoped Shell would give more clarity about its restructuring plans when it reports its third-quarter results on Oct. 29.

Updated: 10-1-2020

Oil’s Recovery Set To Drag On Beyond Next Year

Investment banks polled by WSJ expect an uneven recovery.

Oil prices won’t recover to pre-coronavirus levels by the end of next year, investment banks say.

A group of 10 investment banks polled by The Wall Street Journal forecast that futures for Brent crude oil, the global benchmark, will average $53.50 a barrel in 2021’s fourth quarter. U.S. benchmark West Texas Intermediate futures will average $50.31 a barrel in the same quarter, they estimated.

While that means those institutions expect both benchmarks to rally $10 a barrel from their average forecasts for 2020’s final quarter, they forecast that Brent prices will remain well short of the $60-a-barrel pre-lockdown levels.

Oil BullsThese companies see Brent crude-oil futures rising above $55 in the coming quarters.

Oil prices sharply dropped on Thursday, with Brent crude down 3.2% at $40.93 a barrel and U.S. crude futures 3.7% lower at $38.72 a barrel.

Gentle early losses accelerated after the release of a raft of U.S. economic data that signaled a stalling economic recovery in the U.S., according to Giovanni Staunovo, commodity analyst at UBS Wealth Management. Uncertainty around bipartisan negotiations over a coronavirus relief package was also worrying investors, he added.

Even if the oil market isn’t roiled by the same lockdowns that crashed prices earlier in 2020, investment banks forecast that the effects of Covid-19 will linger next year.

Stalling demand for transportation fuels is one of the key factors weighing on broader oil consumption, with gasoline demand flatlining. The International Air Transport Association this week downgraded its 2020 air-traffic estimate to a fall of 66% from 2019 levels, and U.S. airlines implementing substantial job cuts.

The key risk to oil demand “is definitely the danger from the jet-fuel side, which is underestimated by the market,” said Eugen Weinberg, head of commodities research at Commerzbank.

Still, some major economies are expected to continue to recover in the first half of 2021, leading to lumpy oil-demand recovery across regions. China’s economic recovery has maintained its momentum in recent months, while large parts of Europe have begun to reimpose regional coronavirus restrictions and infection rates in the U.S. remain elevated.

The Federal Reserve’s pledge to hold interest rates near zero for an extended period should keep the dollar weak, providing support over the coming year to dollar-denominated commodities such as oil, according to UBS Wealth Management’s Mr. Staunovo.

A broad, if uneven, recovery in economic growth and oil demand in the first half of next year will likely lift prices, although that could in turn incentivize producers to ramp up output, said Harry Tchilinguirian, global head of commodity markets strategy at BNP Paribas.

“The thing that concerns banks for 2021 is the perennial question of OPEC cohesion: Will they continue tapering cuts if they see no need to withdraw supply,” he said.

The Organization of the Petroleum Exporting Countries and its allies have broadly maintained historic supply cuts agreed upon during the oil-price crash despite the economic pressure felt by oil-producing economies. Still, Saudi energy minister Prince Abdulaziz bin Salman, the cartel’s de facto leader, in September called for better compliance.

There is also the prospect of a resurgence in U.S. production. A September survey of oil executives by the Federal Reserve Bank of Dallas found that more than half of the respondents expect the U.S. oil rig count to increase substantially if WTI prices rise to between $51 and $55 a barrel.

Investment banks don’t see U.S. prices hitting those levels until 2022, when non-OPEC production could once again leave the global oil market with excess supply.

10-2-2020

Shale Companies Had Lousy Returns. Their CEOs Got Paid Anyway

Some of the biggest raises in corporate America went to the executives in charge of U.S. shale companies, even as their shareholders lost billions of dollars.

It’s been a bad few years for investors in shale companies, but a pretty good few years for shale company CEOs.

The leaders of U.S. shale companies received some of the largest executive pay increases in corporate America, even as their shareholders lost billions of dollars, a Wall Street Journal analysis has found.

The median pay for chief executives of large U.S. oil and gas drillers rose for four straight years, hitting $13 million in 2019. That was up from about $9.9 million in 2015, a stretch when the companies’ median total returns to shareholders fell 35%, according to the WSJ analysis of executive compensation data from firm Equilar Inc. and returns figures compiled by Evercore ISI. Taken as a group, the shale CEOs received larger raises in 2019 than peers in all but two of the 11 major industries Equilar analyzes.

Shale companies used hydraulic fracturing and horizontal drilling techniques to unlock a gusher over the past decade, making the U.S. the world’s leading oil producer. But most have struggled to make money. Funded with a wave of Wall Street capital that began flowing in earnest a decade ago, they focused on growth over profit.

Journal articles in 2016 showed that the executive bonus formulas used by many shale companies to compensate CEOs rewarded them handsomely for pumping more, regardless of whether they made money.

Many companies have since tweaked their formulas to add more financial-performance targets in response to pressure from shareholders. But the current formulas still bear little relationship to companies’ bottom lines, the WSJ analysis found.

In many cases, companies boosted the pay of their CEOs because they had performed better than a group of peers that had done even worse. In some cases, boards decided to reward CEOs even when they did not hit their targets.

“You’ve had 10 years of consistent value destruction with management teams getting paid for it,” said Ben Dell, managing partner at private investment firm Kimmeridge Energy Management Co.

Dan Dinges, CEO of Cabot Oil & Gas Corp., was awarded $59.6 million in total pay over the five-year period, averaging $11.9 million a year. The company’s board of directors awarded him cash bonuses that were 54% higher, on average, than the targets it set when arranging his compensation package.

He also got performance-based stock awards that were worth 19% more than their target value on average, as his company’s returns beat peers such as Apache Corp. , Chesapeake Energy Corp. , EQT Corp. and Ovintiv Inc. Still, Cabot’s total returns to shareholders, a measure of stock-price changes and dividends paid, fell 39% in the five-year period.

Cabot did not respond to requests for comment. The company added a new way to measure success, called “returns on capital employed,” to its bonus metrics in 2018, citing shareholders’ push for greater financial discipline.

Marathon Oil Corp. CEO Lee Tillman’s pay in the five-year period totaled about $54.9 million and averaged about $11 million, lifted by annual cash bonuses based on production, pretax earnings and stock grants that were earned by outperforming peers in oil and gas.

By its metrics, Marathon ranked fourth and fifth in the company’s peer group in 2018 and 2019, regulatory filings show. Marathon’s total shareholder returns fell 48% over the five-year period, according to Evercore ISI. Marathon declined to comment.

The Journal compared 19 American frackers worth between $2 billion and $50 billion as of Aug. 3 to U.S. companies of that size in other sectors. The frackers fell behind every major industry in their return on capital employed and trailed all but utilities in the amount of free cash flow they generated over the last five years: negative $25.1 billion, collectively. The group’s shares fell by a median 41% during that period, worse than companies of that size in every segment of the economy.

Problem Areas

Pay increased annually for many shale CEOs despite indicators of poor company health, such as negative returns on capital employed and negative cash flow.

In response to inquiries from the Journal, some companies said their CEOs had also suffered due to the decline in the valuations of their companies, noting that the bulk of their compensation came from long-term stock incentives.

Total pay reported by companies includes salaries, cash bonuses and stock awards that may not vest for years, and will ultimately be less if the stock declines. Indeed, the value of beneficially owned shares held by CEOs of the 19 U.S. oil companies fell by a median of about 53% from the start of 2020 to Sept. 27, according to compensation consultant Farient Advisors LLC.

David Hager, CEO of Devon Energy Corp., was awarded $58.3 million in total compensation over the five-year period, averaging $11.7 million a year. The company’s total shareholder return was negative 55% over the period.

In an interview, Mr. Hager said his actual pay last year of about $7.4 million was about 42% less than the company’s target and the value of his stock that has vested over the past five years was less than 25% of the original reported value.

“We share their [investors’] frustrations, frankly, because the bulk of our compensation does come through stock awards,” Mr. Hager said.

Devon in May said it would cut executive cash compensation about 40% as part of drastic cost-saving measures during the coronavirus pandemic, joining explorers Pioneer Natural Resources Co. , Parsley Energy Inc., Murphy Oil Corp. and others in cutting executive pay.

Mr. Hager is now set to step aside as CEO once Devon closes an all-stock merger with WPX Energy Inc. and he becomes executive chairman. He will not receive severance payments or an accelerated vesting of long-term incentive awards as a result of the deal, a Devon spokeswoman said.

It was unclear whether his change in position would trigger payments from the company’s employee benefit or retirement plans; several compensation consultants disagreed on the implications, and Devon said the matter was under review.

Chesapeake Energy, a shale gas pioneer that was too small to qualify for the WSJ analysis, saw its market cap fall about 88% over the five-year period to $1.6 billion at end 2019, and in June filed for chapter 11 bankruptcy protection. Its CEO Doug Lawler had been awarded $120.8 million in reported compensation since he began his tenure in 2013.

The month before its bankruptcy, it prepaid 21 executives, including Mr. Lawler, about $25 million in retention pay. Regulatory filings showed Mr. Lawler had agreed to a 34% reduction in target variable pay compared with 2019.

Gordon Pennoyer, a spokesman for Chesapeake, said Mr. Lawler was recruited to address the “unprecedented” financial and operational challenges at the industry’s worst-performing company. During Mr. Lawler’s tenure, Chesapeake has cut more than $20 billion in legacy obligations and improved operations.

“Given the recent chapter 11 filing, Lawler’s actual realized pay was approximately 25% of his reported target compensation,” since 2013, Mr. Pennoyer said. He noted Mr. Lawler has not sold any of his shares in the company.

Because the energy sector in general has struggled in recent years, some investors have pushed companies to compare their returns to those of other industries as they compete for investors’ dollars. Apache, ConocoPhillips, and Hess Corp. said they’ll start comparing their returns to the S&P 500’s this year.

“We listen and make every effort to be responsive,” said William Montgomery, chairman of Apache’s compensation committee.

Apache’s move came after directors met with many of its biggest shareholders last fall, he said. Mr. Montgomery noted the company’s say-on-pay vote in 2020 was met with 92% shareholder approval. Apache said CEO John Christmann was required to own 10 times his base salary in company stock.

Still, some investors say the industry’s compensation practices will need a more dramatic overhaul if the companies are to be taken seriously when they promise to focus on operating profitably, even if it means drilling fewer wells.

The California Public Employees’ Retirement System, the nation’s largest public pension fund with $407.5 billion in assets, voted against the executive pay packages and the re-election of compensation committee members for 11 of the 19 independent U.S. oil producers in the WSJ analysis.

Simiso Nzima, an investment director at Calpers, said the pension fund aims to speak with all 19 drillers the WSJ reviewed and will continue voting against companies that fail to respond or fix their compensation practices, hoping to move them toward better metrics.

“If we’re paying top dollar, we expect top-dollar performance,” Mr. Nzima said.

Updated: 10-8-2020

There’s No Oil In Wisconsin. The Fracking Bust Hit It Anyway

Mines that sent trainloads of ‘Northern White’ sand to West Texas sit idle, costing jobs and hurting local-government coffers.

For years, Mary Drangstveit could feel the shale boom reverberating in her kitchen. This spring, oil prices crashed and the rattling ceased.

It brought relief for her and distress for some others in her community.

Digging stopped at the sand mine next door in Blair, Wis., which had rumbled since 2015 to supply drillers with silica they blasted into shale to let out oil and gas. The coronavirus pandemic and a switch by drillers to cheaper sand accomplished what locals like Mrs. Drangstveit, 77, couldn’t in their efforts to fight the mine at town meetings and court.

The mine’s owner, Hi-Crush Inc., filed for bankruptcy in July. Rival Covia Holdings Corp. , an Ohio company with Wisconsin mines, did so in June. Other mines have closed or cut hours. “This has been the most peaceful summer of the last six years,” Mrs. Drangstveit said.

The peace has been disquieting for locals like Joshua Brush, who mowed grass at Hi-Crush properties. He lost his top customer and says $6,530.45 of unpaid invoices are “a huge financial hardship for me and my family.”

The collapse in oil prices this year has squeezed energy-centric economies from Russia to Venezuela, idled drilling rigs in the North Sea and Gulf of Mexico, bankrupted U.S. shale producers and helped push Exxon Mobil Corp. out of the Dow Jones Industrial Average.

Wisconsin doesn’t produce a drop of oil or gas, but there has been a bust there, too, as there has been along the entire industrial ecosystem that supported fracking.

Dozens of idled open-pit sand mines dot the farmland near where Wisconsin, Minnesota, Iowa and Illinois meet along the Mississippi River. Hundreds of mine workers in the sparsely populated region have lost jobs. Many others, like Mr. Brush, are suffering alongside them.

Companies that supplied trucks, lubricants and drilling tools have been bankrupted. Steelworkers in Youngstown, Ohio, have lost jobs providing pipe to the oil patch. Apartments and hotels hastily built to house roustabouts in North Dakota and remote parts of Texas have emptied.

Few of the shale boom’s sideshows have flamed out quite like Wisconsin’s Northern White sand. Local governments that envisioned the mines bringing long-term prosperity are looking at budget crunches. Investors have lost more than $10 billion on sand-mining stocks.

Mixed Blessing

Miners of the region’s Northern White sand became stock-market stars a decade ago when oil-industry engineers settled on the pebbly grains ideal for hydraulic fracturing.

Frackers blast a slurry of sand, water and chemicals into fossil-fuel-bearing rocks. The grains prop open fissures to let oil and gas flow out. Energy companies prized Northern White for its crush strength, grain size and roundness, which helps prevent plugs. There is a sea of such sand beneath western Wisconsin topsoil.

The sand was long mined for glassmakers and cranberry growers. Suddenly, oil companies wanted trainloads delivered 1,200 miles away in West Texas as well as to drilling fields in Appalachia and North Dakota. Small farming towns allowed miners to gouge away at the countryside, hoping to pay for public services, create high-paying jobs and keep young people from leaving.

The sand mines were a mixed blessing, with disputes breaking out between residents wanting to participate in the shale-drilling boom that was helping to lift the economy from the 2007-09 recession and those decrying the environmental impact.

“We were in the hot seat, so to speak, in figuring out what to do about these mines,” said Jeff Hauser, mayor of Whitehall, Wis. “During all my time on the city council, it was one of the most emotional issues I had to deal with.”

Some residents saw spoiled countryside and worried about dust and noise. Others saw starting wages that were $5 to $8 an hour more than the typical jobs around that didn’t require a college degree. By 2012, there were about 60 frack-sand mines in Wisconsin and 20 more on the drawing board.

Mining companies provided local governments with tax payments, royalty checks and contributions to civic projects. In Blair, a city with a cheese factory and about 1,350 residents, funds from Hi-Crush helped pay for a new public swimming pool after the city annexed land for the company’s 1,285-acre mine.

The annexation let Hi-Crush avoid the permitting process in surrounding Trempealeau County, which had a history of putting up obstacles to miners.

A Hi-Crush spokeswoman said: “The entire annexation process was completed openly, publicly, and in a fashion that provided all residents with the opportunity to participate.”

In nearby Independence, Wis., the company gave the police $27,000 to buy a dog, named Crush in the donor’s honor.

The Organization of the Petroleum Exporting Countries sent oil prices tumbling on Thanksgiving 2014 when it decided it wouldn’t hold back its output against the flood of U.S. shale oil. Frackers fought falling prices by boosting production.

They drilled bigger wells and used more sand. Rail companies laid spurs to mines. In 2016, shale driller Chesapeake Energy Corp. revealed good results from pumping more than 50 million pounds of sand—about 1,000 truckloads—into a single Louisiana well. Other producers ramped up their sand use, especially in West Texas’ Permian Basin.

Nearly half of what drillers paid for Northern White was spent getting it from Wisconsin to the West Texas desert, said Rene Santos, an analyst with S&P Global Platts.

By 2017, oil producers knew shale wells petered out quickly. The Permian’s smaller-grain brown sand could keep fractures open long enough and came with smaller freight bills. Chesapeake executives who packed wells with Northern White were now telling investors the company was saving as much as $900,000 a well, or $100 million a year, using whatever sand was nearby.

Hi-Crush opened mines in Texas, piling more sand onto the market. In September 2018, Hi-Crush laid off 37 workers at a mine in Whitehall. Layoffs spread in 2019 and accelerated this year with the pandemic.

March Shock

In March, sand supplier U.S. Silica Holdings Inc. laid off Duane Wilke from his job as an environmental health and safety manager when it idled its plant in Sparta, Wis. The 54-year-old found a new job at a heating and ventilation company that offered a similar base salary but inferior benefits, he said. Former colleagues are still unemployed. U.S. Silica said it expects sand demand to recover with oil prices.

Before the slump, mining companies had paid annual bonuses, matched 401(k) contributions and raffled off prizes like hunting rifles and ice-fishing shacks at holiday parties. When Mr. Wilke began working in sand mining in 2011, he said, “I thought the job was going to be pretty secure until retirement.”

A wave of job losses hit the sand industry this spring after coronavirus lockdowns and a Saudi-Russian production feud sent crude prices tumbling. Hours worked in Wisconsin’s mines during the first half of 2020 fell more than two-thirds from the same period in 2018, according to the federal Mine Safety and Health Administration. By July, Wisconsin and neighboring states had lost more than 650 mine jobs, according to public layoff notices.

About a dozen mines remain operating in Wisconsin, down from 69 in 2016, according to the Wisconsin Department of Natural Resources. During a September visit, just a few workers could be seen at Hi-Crush’s sand mine in Blair. A mound of sand towered over a cornfield, and dozens of railcars sat idle.

When it filed for bankruptcy, Hi-Crush said it had $699 million of debt and obligations, including a monthly bill of more than $2.3 million for leases on roughly 5,000 railcars it was barely using. Covia claimed $1.6 billion, including a $5.9 million-a-month railcar bill.

Hi-Crush has said it expects to emerge from bankruptcy proceedings by mid-October. The company spokeswoman declined to comment further about the bankruptcy. Covia declined to comment.

Local governments are hurting. Beyond business and property taxes, miners often paid a fee for every ton they excavated, which added up to hundreds of thousands of dollars a year for some communities.

In Blair, taxes from Hi-Crush covered about one-tenth of this year’s $1.4 million municipal budget. That doesn’t include an annual $300,000 payment Hi-Crush agreed to pay the city as long as the mine runs.

Blair officials say they are bracing for the possibility that revenues from Hi-Crush next year may fall short, as they hold meetings this week to draft a 2021 spending plan. “Hi-Crush has been good to work with in the years they have been here,” said Susan Frederixon, Blair city clerk and treasurer.

The Hi-Crush spokeswoman said the company is committed to paying all taxes when due and will honor agreements with municipalities.

Environmental Toll

While the sand mines gave a boost to local economies, they also took an environmental toll. Neighbors worry chemicals used in sand processing could leach into drinking water. In 2018, Hi-Crush deliberately breached a retention pond in an effort to rescue a trapped bulldozer operator, releasing some 10 million gallons of orange-hued water onto farmers’ fields and the nearby Trempealeau River.

Testing by state officials found no immediate risk to human health, though it did find elevated levels of arsenic and some heavy metals. Hi-Crush said the release saved the operator’s life and committed to clean up afterward. “We are in the final stages of the restoration process,” the spokeswoman said.

In a 2018 study, University of Wisconsin-Eau Claire researchers found air samples taken near two sand mines had elevated levels of a particulate matter associated with increased lung-cancer risk.

And while sand-mining companies in Wisconsin are required to set aside money for reclamation, such efforts in open-pit mines rarely succeed, said Ted Auch, an environmental scientist at FracTracker Alliance, a nonprofit that tracks fracking’s impact:

“The inherent fertility of these sites is lost.”

Some mining companies believe the biggest and most efficient mines will rumble again once oil demand picks up. In September, workers shuttled around loaders at Smart Sand Inc.’s mine near Oakdale, Wis., which remained open with reduced staff thanks to its scale and access to two major railroads, the company said.

“Will all the mines come back? Probably not,” said Thomas Young, a Smart Sand manager and president of the Wisconsin Industrial Sand Association. He sees hope in research showing wells are more productive over time when fracked with Northern White than with Texas sand.

Wall Street and energy analysts are less optimistic. Even after the mine closures, sand supply is about double demand, said Mr. Santos of S&P Global Platts. The combined stock-market value of the remaining miners is under $300 million these days, off more than $10 billion from their peak.

Marc Bianchi , a Cowen Inc. analyst who studies the miners, used to line up first to question executives during earnings calls and then spend days parsing the results with excited investors. His phone no longer rings after quarterly results come out.

Updated: 10-12-2020

Libya Restarts Oil Production At Biggest Field

Sharara currently pumping 27,000 barrels a day, and can contribute an additional 300,000 barrels a day.

Production at Libya’s largest oil field restarted Sunday afternoon, Libyan officials said, a move that could quickly increase the country’s overall output after an extended shutdown and add to a glut of oil on world markets that has kept prices low.

Libya’s central government and rebel commander Khalifa Haftar agreed last month to lift a nine-month oil blockade after the two sides resolved a dispute over oil revenue distribution. The country’s oil output has already increased to 300,000 barrels a day from about 100,000 barrels a day in the past two weeks.

Sharara can contribute an additional 300,000 barrels a day, the officials said. Its initial output was 27,000 barrels a day as of Sunday. Output at the field has been shut almost continuously since early January—except for a short resumption in June.

The slow return of Libya’s shutdown production has already put downward pressure on oil prices, and is a consideration in a debate in Saudi Arabia over whether to boost production from next year.

Libya, one of the worlds biggest producers, pumped some 1.3 million barrels a day before the standoff forced officials to shut down production.

Updated: 10-25-2020

Big Oil Loses Refining Crutch With Margins Crushed Last Quarter

Six months on from crude’s era-defining price crash and Big Oil is suffering from whiplash.

Prices may have stabilized around $40 a barrel as OPEC+ curbed supply, but as the coronavirus surges through Europe once again, the twin safety nets for majors in previous downturns — refining and trading — have come under severe pressure as consumers stay home.

“Refining margins are absolutely terrible,” Patrick Pouyanne, Total SE’s Chief Executive Officer, said earlier this month. The French major, along with a raft of other oil companies and refiners, have warned investors that slumping margins will be a drag on profits. For some like Exxon Mobil Corp., it might even push them into the red.

The third quarter will provide little respite to the supermajors with three out of the five expected to post losses. Trading, which brought the European firms a torrent of cash last quarter, is unlikely to save the day this time around.

But will there be any glimmers of hope for the end of the year? BP kicks off earning seasons on Tuesday, followed by Italy’s Eni SpA on Wednesday. Royal Dutch Shell Plc will announce results on October 29, while Total, Exxon and Chevron Corp. will do so on October 30.

Here Are Five Themes That Delve Into What The Quarter Might Bring For Big Oil:

1. Negative Margins

While oil prices have stabilized from the historic lows seen in the second quarter, travel restrictions, local lockdowns and a growing second wave of Covid-19 has put a lid on oil consumption in many parts of Europe. The hit to demand has pushed a growing list of refiners to post negative margins — meaning they lost money when turning crude oil into consumable refined products like gasoline — in some cases, for the first time.

Earlier this month, Total reported a negative European refining margin of minus $2.70 a ton. Barclays analysts subsequently lowered its expectations for lower earnings for the company in the second quarter.

“The main source of difference to our expectations was in the downstream, where the reference refining margin fell below zero for the first time we can remember,” analyst Lydia Rainforth wrote in a research note.

Shell warned of “significantly lower” margins compared with the second quarter, while Exxon also flagged deteriorating performance at its global network of refineries. This weakening will reduce earnings by as much as $600 million, likely causing a third consecutive quarterly loss, the company said in a filing earlier this month.

And it’s not just Big Oil. Smaller refiners are feeling the pinch. On the Iberian Peninsula, Repsol SA and Galp Energia have reported refining has become increasingly uneconomic. Further east, MOL Hungarian Oil & Gas Plc reduced its earning projections for the full year after margins fell below zero from mid-May.

Italy’s Saras SpA said it would run its Sarroch refinery in Sardinia at a minimum after refining margins “sharpened during the third quarter.” The plant, one of Europe’s largest, is geared toward the production of jet fuel and diesel, where the slump in profits per barrel has been most severe.

2. Trading Bonanza Fizzles Out

Virtually every aspect of Big Oil’s business, from the pump to upstream production was pummeled in the second quarter, save one area: oil trading. A windfall from the division saved Shell, Total and Equinor ASA from posting losses. For BP, it was the one bright spot in an otherwise dismal period.

While majors don’t disclose how much money trading units bring in, executives acknowledged it had been an extraordinary quarter. Total’s Pouyanne said it made about $500 million more than usual. For Shell, it was “the best on record,” while for BP the unit delivered an “exceptionally strong result.”

Traders at the firms had benefited from wild volatility and in particular, so-called contango plays. The trade involves buying cheap crude, storing it and locking in a profit by selling it at a higher price in the future on the derivatives market.

Contango and volatility have since eased, meaning the divisions are unlikely to replicate the success. Shell warned that the unit’s performance will be “below average” in the third quarter.

U.S. rivals rivals Exxon and Chevron for the most part steer clear of pure trading. Exxon did start a modest trading operation two years ago, but the supermajor’s division bucked the trend last quarter having experienced “unfavorable” derivative impacts in its trading division.

3. Dividend Doubts

The first half of the year brought disappointing news to income seekers. Shell cut its dividend for the first time since World War II in April, while BP followed suit in August. Before the cut, the companies were respectively the first and third biggest dividend payers on London’s FTSE 100 Index. While Total has managed to keep it’s payout untouched, European peers Eni SpA and Equinor ASA went for a cut.

Across the Atlantic, Chevron and Exxon have repeatedly told investors that keeping the dividend is a priority. Yet Exxon has failed to generate enough cash to pay for its dividend and capital spending for each of the last eight quarters, putting the quarterly payout, the third-highest in the S&P 500 Index, under severe pressure. Executives have vowed to find additional cost savings to defend the payout, but investors are not convinced. The stock’s dividend yield is currently over 10%, indicating that a cut is imminent.

4. LNG Lag

Investors have been given plenty of warning that the brunt of Covid-19’s impact on liquid natural gas trading is only hitting balance sheets now. The largest LNG producers typically sell under long-term contracts that are linked to oil prices. These usually have a lag of three to six months.

Shell, the world’s largest LNG trader, is expecting a “significant impact” on LNG margins in the third quarter. About 80% of its term sales this year are linked to oil and have a price lag of up to six months, it said in a trading update.

Chevron too is likely to be impacted by LNG pricing delays. The company, which has a large LNG presence in Australia, sells most of its production through oil-linked long-term contracts.

Brent’s crash in April has now made long-term contracts cheaper than spot LNG deals, where prices in contrast surged in past weeks amid higher demand in Asia and supply issues at a number of producing plants.

In addition to price and demand issues, Chevron and Shell have been struggling with technical problems at their multi-billion LNG facilities – Gorgon and Prelude – in Australia.

5. Shale Consolidation

America’s shale patch entered full-blown merger mode this month with a series of multi-billion dollar deals aimed at cutting costs and scaling up operations in a fragmented and beleaguered industry. What role the majors play in the shake up, if any, remains front and center of investors’ minds.

Chevron is the only integrated oil company to participate so far this year, with a $5 billion purchase of Noble Energy Inc. completed in early October and it has the financial resources to strike again. Exxon is cash strapped while investing in shale oil would jar with some European companies’ strategies of pivoting toward renewables. Still, opportunities abound with sellers agreeing to takeovers at modest premiums.

Updated: 10-25-2020

Cenovus And Husky To Merge In $2.89 Billion Deal

Move would create third-largest oil and natural-gas producer in Canada.

Canadian oil-sands producer Cenovus Energy Inc. and Husky Energy Inc., controlled by Hong Kong billionaire Li Ka Shing, agreed to merge in an all-stock deal valued at 3.8 billion Canadian dollars, equivalent to US$2.9 billion.

The deal, unveiled early Sunday, would create the third-largest oil and natural-gas producer in Canada and the second-largest Canadian refiner. Husky shareholders would receive a roughly 21% premium to their shares, the companies said.

The transaction marks the latest in a wave of energy deals, as companies merge after a drop in energy prices this year. This deal follows others by ConocoPhillips, which agreed to buy Concho Resources Inc.; Pioneer Natural Resources Co, which agreed to acquire Parsley Energy Inc. ; and Devon Energy Corp. and WPX Energy Inc., which agreed to merge.

The companies began talks about a tie-up in the spring, as oil prices crashed because of the economic slowdown caused by the Covid-19 pandemic and after major oil producers Saudi Arabia and Russia split over a plan to cut global supplies.

Though prices since have recovered from their lows, the weak economic conditions have weighed on crude, which has hurt oil-company stock prices. Cenovus’s stock has dropped roughly 63% this year, while Husky’s shares have fallen almost 70%.

“With just how quickly the oil price collapsed…we really felt the pain of that,” said Alex Pourbaix, Cenovus’s chief executive, who will remain in that role after the merger. He said the combination will allow the company to lower its production costs and pay down debt more quickly.

Husky CEO Robert Peabody said the deal will give the combined company more access to capital, as investors are increasingly looking to invest in the larger companies. “Scale is becoming more and more important in order to be relevant to the investor,” he said.

The transaction is expected to close in the first quarter of 2021 and would leave Cenvous shareholders with 61% of the combined business. Husky shareholders, including Mr. Li’s Hutchison Whampoa conglomerate, would own the remainder.

Hutchison’s investment in Husky has lost a lot of value in the last decade. At its peak in 2008, Husky’s market value was just over $38 billion on the Toronto Stock Exchange.

As part of the transaction, Mr. Li’s company agreed to a five-year standstill agreement, meaning it won’t sell shares until the agreement expires. That should signal to investors the conglomerate won’t unload its shares and put pressure on the stock price, Mr. Pourbaix said.

The companies, with oil projects in Canada’s oil sands, also have been struggling to find ways to get that crude out of the landlocked Western province of Alberta to refiners in the U.S. The deal will now boost the merged company’s access to refining capacity in the Midwest and the Gulf Coast.

Husky has about 410,000 barrels per day of refining capacity, compared with Cenovus’s 250,000. The companies together will roughly double the number of barrels they can export from Alberta on pipelines to 265,000 barrels a day.

The companies also expect to cut $457 million in costs after closing the deal, by shedding jobs and cutting overhead.

Updated: 10-29-2020

Exxon To Slash Up To 15% Of Global Workforce, Including 1,900 Jobs In U.S.

The oil giant plans to shed employees and contract workers world-wide over the next year as it struggles during the coronavirus pandemic.

Exxon Mobil Corp. said it expects to shed as much as 15% of its global workforce over the next year, including 1,900 jobs in the U.S., as the coronavirus pandemic continues to batter the oil industry.

The steep job cuts, which follow similar layoff announcements by rivals Royal Dutch Shell PLC, BP PLC and Chevron Corp., are part of a wholesale effort by the beleaguered industry to restructure itself to weather the worst downturn in a generation. In all, big oil producers and services firms are collectively shedding more than 50,000 jobs.

Exxon is in the midst of one of its toughest stretches ever after Chief Executive Darren Woods, who took over in 2017, embarked on an ambitious plan to reverse the company’s declining fortunes by dramatically increasing oil production by 2025. In hindsight, Exxon’s heavy spending on new output now appears spectacularly ill-timed and has put its finances under severe stress.

New lockdowns in Europe in response to climbing Covid-19 cases are damping hopes that the global economy will regain its footing this year, severely crimping demand for oil and gas. That is combining with longer-term concerns about future competition from renewable energy and electric vehicles to drag down the value of many oil-and-gas companies to decade lows.

Exxon announced the U.S. job cuts Thursday, and in response to questions added that it anticipates it will eliminate around 14,000 positions, including employees and contractors, through 2021. It said most of the cuts to U.S. employees would come from its management offices in Houston and that it expects the reductions will be both voluntary and involuntary.

Noah Barrett, an analyst at Janus Henderson Investors, said the severity of the industrywide job cuts suggest that they are not temporary, but instead a signal that the companies are repositioning themselves for an uncertain future.

“It’s maybe a sign of a greater appreciation that the impact of this downturn is more structural than cyclical,” Mr. Barrett said. “Even if demand improves, even if we get some type of vaccine, on a go forward basis, the world may just need less oil.”

Despite a modest economic recovery, oil-and-gas companies are being hammered by a sustained drop in consumption of gasoline and jet fuel as millions of people work from home and avoid driving and flying during the pandemic.

The International Energy Agency said earlier this month that a prolonged pandemic could eliminate more than 4 million barrels of oil a day from global demand for much of the decade. The world consumed nearly 100 million barrels a day before the pandemic.

U.S. oil prices fell to $36 per barrel Thursday, their lowest prices since June.

Exxon made the latest announcement a day before it is set to report quarterly earnings. Analysts expect the company to post its third consecutive quarterly loss for the first time on record.

Exxon has said it is conducting a global review of its 74,000 employees and more than 13,000 contractors, and previously announced 1,600 layoffs in Europe and voluntary layoffs in Australia.

Shell said in September it would cut up to 9,000 jobs in a broad restructuring, and BP plans to cut nearly 10,000 jobs, or 14% of its workforce, and freeze pay increases for senior level managers. U.S. rival Chevron has said it would reduce its 44,679 workforce by as much as 15%.

Exxon’s shares have fallen more than 50% this year, and the company has had to borrow billions of dollars to pay its costly dividend. Its shares were up more than 3% Thursday following the layoff announcement.

Shell and BP cut their dividends earlier this year to shore up their finances. Exxon and Chevron said this week they would maintain their current dividend payments. Exxon’s dividend, which currently yields around 10%, costs the company about $15 billion a year.

Exxon said earlier this year it would cut its capital expenditures by $10 billion to around $23 billion and has slowed projects from West Texas to Africa. It suspended matching contributions to U.S. employees’ retirement plans in October.

Exxon struggled prior to the pandemic after U.S. shale producers unleashed vast amounts of oil and gas, helping push down global prices. It has been six years since Brent oil, the global benchmark, topped $100 a barrel.

Between 2009 and 2019, Exxon spent $261 billion on capital expenditures, while its oil and gas production remained flat, and it added $45 billion in debt, according to investment bank Evercore ISI. Its return on capital employed in 2009 was 16%; last year, it was 4%.

Analysts predict that Exxon will have to continue borrowing money to cover its dividend next year, let alone grow production.

In a message to employees last week, Mr. Woods said the company faces significant headwinds and would succeed by becoming more efficient and cutting costs, including jobs. But Mr. Woods said oil demand will ultimately continue to grow while investment in production shrinks, justifying Exxon’s long-term plans.

“Even accounting for the short-term demand impact of Covid-19, the investment case is still clear,” Mr. Woods wrote.

Exxon Posts Third Consecutive Quarterly Loss For First Time

Oil giant warns it may write down natural-gas assets worth billions as the pandemic continued to weigh on fossil fuel companies.

Exxon Mobil Corp. posted its third consecutive quarterly loss for the first time on record Friday and disclosed that it may write down the value of natural-gas assets worth as much as $30 billion, as the coronavirus pandemic continues to pressure the world’s biggest oil companies.

The Texas oil giant reported a loss of $680 million in the third quarter compared with a profit of $3.17 billion during the same period last year.

Exxon Chief Executive Darren Woods invested heavily before the pandemic to grow Exxon’s oil and gas production by 2025. That decision has backfired as commodity prices plunged this year, forcing the company to make substantial cuts and painful choices about where to invest.

“We are on pace to achieve our 2020 cost-reduction targets and are progressing additional savings next year as we manage through this unprecedented down cycle,” Mr. Woods said.

Rival Chevron Corp. on Friday posted a third-quarter loss of $207 million compared with a profit of $2.58 billion in the same quarter last year. Royal Dutch Shell PLC reported a profit of $546 million Thursday, while BP PLC lost $307 million.

The results make clear that the pandemic continues to weigh on the industry despite a modest economic recovery and rebound in demand for oil and gas. New lockdowns in Europe are conjuring fears that rapidly climbing virus cases could mean a prolonged global recession.

“I think the industry would say this is their nightmare scenario,” said Regina Mayor, who leads KPMG’s energy practice.

On Thursday, Exxon said it could cut as much as 15% of its global workforce, or about 14,000 jobs, as the struggling oil company tries to cut costs and survive the Covid-19 downturn. In all, big oil producers and services firms are collectively shedding more than 50,000 jobs.

“The world’s economy continues to operate below pre-pandemic levels, impacting demand for our products which are closely linked to economic activity,” Chevron CEO Michael Wirth said Friday.

Lower oil and gas prices brought on by the pandemic and uncertainty over the pace of the transition to lower-carbon energy have caused major oil companies to question the value of their assets.

Exxon had stood out among its peers this year for resisting large write-downs. Its disclosure Friday that it could take a huge one comes after months of pressure from analysts and others who argued it needed to do so.

Shell said earlier this year it would write down the value of its assets by up to $22 billion because of lower energy prices, and BP is writing down as much as $17.5 billion. Last year, Chevron said it would cut the value of its assets by $10 billion.

Exxon Senior Vice President Andrew Swiger said on an investor call Friday that it is strategically evaluating which assets are worth investing in under current market constraints and could move to sell some its North American dry gas assets with a carrying value of $25 billion to $30 billion, potentially resulting in an impairment.

Spokesman Casey Norton said Friday that the impairment hadn’t been completed and would be considered by the board later this year. Mr. Norton said the impairment doesn’t indicate changes to Exxon’s long-term price views and isn’t a reaction to short-term price fluctuations.

If Exxon were to write down close to the full value of those assets, it would be among the largest-ever charges taken by an oil-and-gas company, according to analysts.

The company also said it would reduce its capital expenditures to between $16 billion and $19 billion next year. Exxon had planned to spend $33 billion in 2020, but cut its capital expenditures to $23 billion after the pandemic took hold.

Paul Sankey, an analyst who has long called for Exxon to write down the value of its shale gas assets, said the impairment was overdue.

“It never made sense that there wasn’t the mother of all write-downs,” said Mr. Sankey, the lead analyst at Sankey Research.

As The Wall Street Journal previously reported, several oil and gas accounting experts have alleged that Exxon’s reticence to adjust the value of assets on its balance sheet amounts to accounting fraud in a series of complaints filed to U.S. authorities.

By their estimates, Exxon should have taken a $44 billion impairment loss this year and a corresponding $56 billion reduction of its reported assets on its balance sheet in the second quarter.

The group, which filed a whistleblower complaint with the Securities and Exchange Commission, has singled out Exxon’s acquisition of XTO Energy Inc., a natural-gas driller it purchased for $31 billion a decade ago, along with other assets.

Exxon has rebutted the criticism of its write-down practices, saying that the company is in compliance with accounting rules and SEC regulations about disclosures to investors.

Exxon has said it is able to avoid write-downs because it is extremely conservative in initially booking the value of new fields and wells and doesn’t respond to short-term commodity-price fluctuations. Before 2016, Exxon had never recognized an asset impairment under U.S. accounting rules implemented in the 1990s.

Despite the capital constraints imposed by the pandemic, Mr. Swiger said Friday Exxon would continue to maintain its hefty dividend, and that its long-term plan to grow production is unchanged because energy demand will ultimately grow.

“While questions remain around future demand recovery, one thing is certain,” Mr. Swiger said. “Current conditions cannot continue, supply and demand will eventually meet.”

Exxon’s production increased to 3.7 million barrels a day, up 1% from the second quarter but down nearly 6% from the same period last year. Exxon’s oil and gas production unit posted a $383 million loss in the third quarter, while its downstream and refining business lost $231 million in the quarter.

Chevron’s production unit eked out a profit of $235 million, producing 2.83 million barrels a day in the third quarter, down 7% from a year ago. Its downstream earnings fell to $292 million from $828 million.

Chevron Chief Financial Officer Pierre Breber said on a call with analysts Chevron would continue to cut costs next year and expects to spend around $10 billion in capital expenditures in 2021.

“We’re in an economy that’s impacted by pandemic, and demand for our products is below normal levels in pre-pandemic levels,” Mr. Breber said. “We are trying to sustain the long-term value of the enterprise.”

Updated: 10-31-2020

Libya’s Daily Crude Output Surges To 800,000 Barrels A Day

Libya’s daily crude output has reached 800,000 barrels per day and the country is targeting 1.3 million barrels at the beginning 2021, according to Mustafa Sanalla, the chairman of state-run National Oil Corp.

The reopening of the last of Libya’s oil fields and ports has prompted a resurgence of the energy industry, with the OPEC nation’s daily production jumping from less than 100,000 barrels in early September. The Waha oil field, one of Libya’s biggest, resumed production on Saturday, Ahmed Ammar, chairman of Al Waha Co., said on the sidelines of a meeting in Sirt Company in Buraiqa city.

The return of Libyan barrels is hindering OPEC+ as it tries to prop up crude prices amid a resurgence in coronavirus cases and with many major economies imposing lockdowns again. The oil producers’ alliance was set to ease supply cuts by almost 2 million barrels a day in January but may be forced into a delay.

“We’re very interested in coordinating with our colleagues in OPEC,” Sanalla said in an interview Saturday. “We’re interested in achieving a balance in terms of supply and demand.” Libya’s share in OPEC is 1.7 million barrels daily.

The National Oil Corp. expects the country to pump 1 million barrels daily next month, Sanalla said. Its ambition to reach 1.6 million by the end of 2021 hinges on the resources the Finance Ministry will allocate to the company, he said.

Waha restarted production at an initial level of 10,000 barrels a day, according to a person familiar with the matter who asked not to be identified because they aren’t authorized to speak to media. Waha’s production was 320,000 barrels a day before the shutdown in January.

The industry was shut down in January when supporters of Khalifa Haftar, a Russian-backed commander trying to defeat the United Nations-recognized government of Prime Minister Fayez al-Sarraj, blockaded ports and fields. A cease-fire that’s been in place since June was formalized by representatives of the two parties on Friday.

Updated: 11-10-2020

BP Steps Up Green Drive With Hydrogen Deal

Oil major teams up with Ørsted to produce hydrogen using wind power.

BP BP PLC is partnering with renewable energy giant Ørsted ORSTED to produce hydrogen from wind power, the oil major’s first big project in a sector that it—and the wider industry—believe will play a key role in the transition to low-carbon energy.

Using renewable power such as wind and solar to produce hydrogen, instead of fossil fuels such as gas or coal, is expected to be important for reducing global carbon emissions—although it remains a more expensive option. While hydrogen only makes up a small amount of the world’s energy use—mostly for refining and chemical production—it is responsible for significant emissions.

Under the deal announced Tuesday, BP said it would use wind energy from Ørsted’s North Sea wind farm to produce hydrogen for its Lingen refinery in northwest Germany. The two companies intend to build a 50 megawatt electrolyser, powered by wind, to split water into hydrogen and oxygen gases without generating carbon emissions.

The partnership is part of a broader plan BP detailed in September to cut its oil and gas production by 40%, while increasing spending in low-carbon energy, including green hydrogen. It is targeting a 10% market share of hydrogen produced using renewables—or natural gas in cases where the emissions have been captured and stored—within the next decade.

Other oil companies also have plans to reduce emissions from hydrogen. Royal Dutch Shell PLC plans to increase its green hydrogen production 10-fold at its Rhineland refinery in Germany by 2030. Earlier this year, Repsol SA said it would build a fuel plant, which uses green hydrogen in Northern Spain.

Advocates say that as well as reducing emissions, green hydrogen could help address the storage issues facing renewable energy, which is typically generated when the wind blows or the sun shines, regardless of whether there is demand for the power. By using excess renewable power to produce hydrogen, the energy could be stored for later use.

One challenge remains, however, cost. Producing hydrogen using renewable energy is more expensive than that using fossil fuels, and analysts say government support will be key to its adoption. While the costs of electrolysers and renewable electricity have been coming down, green hydrogen still doesn’t compete with natural-gas based hydrogen.

To support the project in Germany, BP and Ørsted have applied for funding from a European Union innovation fund that focuses on projects aimed at reducing emissions.

The companies said they plan to make a final investment decision in early 2022, and anticipate the project could be operational by 2024. BP didn’t disclose financial details of the project.

“Renewable hydrogen has to become cost competitive with fossil-based hydrogen, and for that we need projects such as this,” said Dev Sanyal, BP’s executive vice president for gas and low carbon energy, adding that the project would demonstrate the technology at a large scale.

Updated: 11-12-2020

Oil-Demand Recovery Unlikely For Months Despite Vaccine Hopes

Lockdowns, rising coronavirus cases prompt IEA to further cut demand forecasts.

Global oil markets may have rallied on the latest positive vaccine trial results, but they are unlikely to feel any significant economic benefits until well into next year, the International Energy Agency said Thursday.

In its monthly report, the IEA darkened its outlook for crude consumption in the months ahead, citing resurgent Covid-19 infection rates in the U.S. and Europe. It now expects demand for 2020 to fall by 8.8 million barrels a day this year—400,000 barrels a day more than its last forecast. That is more severe than OPEC’s forecast cut Wednesday.

The agency also slashed its demand forecasts for the third and fourth quarters of 2020 as well as the first quarter of 2021, all while estimating a supply increase of more than a million barrels a day in November. Libyan supply is rebounding from its monthslong export blockade and U.S. production is recovering after hurricane-induced shut-ins in October. U.S. production was down 7% from its average 2019 level last month.

After a mild start to the winter season in the Northern Hemisphere, when people begin to turn on their heating, new lockdowns across Europe and rising infection rates in the U.S. prompted the Paris-based organization to cut its fourth-quarter demand estimate by 1.2 million barrels a day. A Covid-19 vaccination won’t significantly affect global demand in the first half of 2021, the IEA said.

Oil prices swung between gains and losses Thursday, after giving up modest early gains following the report’s publication. Brent crude, the global benchmark, finished the trading session down 0.6% to $43.53 a barrel and U.S. crude futures fell 0.8% to $41.12. Both benchmarks are up more than 10% so far this week.

The IEA’s report highlighted the stark disparity between the impact of the coronavirus in richer countries and in their poorer counterparts.

“Nearly all of these massive reductions are found in OECD countries,” the IEA said, pointing out that in the economic powerhouses of the developing world such as China and India, demand expectations have improved.

Even so, with a tentative summer recovery in demand having faltered and production rising despite the best efforts of the Organization of the Petroleum Exporting Countries and its allies to balance the oil market with production cuts, the world has failed to winnow away much of the glut of crude that prompted vertiginous price drops during the spring.

OECD stocks in September were only 4% below their May highs, according to the IEA.

And while stocks of refined products finally fell in September after six consecutive months of increases, the pandemic has hammered refiners. The pandemic has permanently removed 1.7 million barrels a day of refining capacity from the market, while a further 20 million barrels a day of capacity has been idled, the report said.

In a sign that the oil market is well supplied, the price of physical barrels of crude remains below that of oil futures. The IEA sees any vaccinations “unlikely to ride to the rescue of the global oil market for some time.” Therefore, current supply and demand may give OPEC pause for thought when it meets later this month and with its non-cartel allies in early December.

The alliance has signaled its willingness to delay or reverse plans to further ease production cuts. Without such a move, the IEA’s forecasts imply that there will be almost zero change to oil stocks in the first three months of 2021.

“Unless the fundamentals change, the task of rebalancing the market will make slow progress,” the IEA said.

Updated: 11-16-2020

Aramco Plans U.S. Dollar Bond To Plug Funding Gap

With the bond issue, the Saudi oil giant is seeking to meet its $75 billion annual dividend pledge.

Saudi Aramco said Monday it aims to issue a U.S. dollar-denominated bond, as the cash-strapped oil giant cuts jobs, considers asset sales and reviews its expansion plans.

Saudi Arabian Oil Co., as the company is officially called, is selling debt even as low oil prices hurt its ability to generate cash for its biggest shareholder, the Saudi government. It is seeking to meet a pledge made last year to pay $75 billion in annual dividends.

Aramco in a statement said it hired Goldman Sachs Group Inc., Citigroup Inc., JPMorgan Chase & Co. and Morgan Stanley, among others, to arrange investor calls on Monday ahead of a debt sale. The oil company, which didn’t disclose pricing or how much it will raise, said it plans a multi-tranche bond offering with potential maturities of three, five, 10, 30 and 50 years.

The bond issue is likely to raise billions of dollars, and the pricing and size would depend on market conditions, Aramco added.

It could be well timed. Investors are hopeful of a global economic recovery after Pfizer Inc. last week said its coronavirus vaccine was 90% effective in trials. Oil prices have rallied since then.

Aramco made its debut in the bond markets last year, raising $12 billion and giving global investors access to the world’s biggest oil company for the first time. The sale prospectus also opened the books on Aramco’s once-secretive financials, showing it was then the world’s most profitable company and whetting the appetite for equity investors ahead of last December’s share offering.

The company announced the dividend commitment in a bid to lure investors to the initial public offering. But the pledge, combined with low oil prices caused by the pandemic, has forced a restructuring at Aramco and a scramble to raise cash. The IPO also failed to attract international buyers, many of whom were discouraged by what they perceived to be an expensive valuation.

On top of raising debt, Aramco is now cutting jobs and reviewing plans to expand at home and abroad, The Wall Street Journal has reported. The company is also considering a sale-and-lease-back agreement for some of its pipeline assets in a deal that could also raise billions of dollars, according to people familiar with the deal.

The plan, dubbed “Project Seek,” could involve Aramco selling a stake in its infrastructure to investors who would receive a regular payout from the company as it leases the asset, these people said.

Aramco didn’t immediately respond to a request for comment on the project.

Earlier this month, the company posted a 45% fall in net income for the third quarter, generating free cash flow of only $12.4 billion, compared with the roughly $18.75 billion it requires each three months to meet its dividend pledge.

Aramco isn’t the only major oil company battling to keep its dividend. Exxon Mobil Corp. has also held the line on dividends, instead trimming jobs and capital spending. Other big oil companies such as Royal Dutch Shell PLC and BP PLC have cut payouts to preserve cash amid falling oil demand as a result of the coronavirus.

Since the onset of the pandemic, Aramco’s dividend payout has become even more crucial to the Saudi government, which has had to contend with higher costs related to a national lockdown and a stimulus effort to boost the economy. The government owns roughly 98% of the oil company’s shares.

Ratings agency Fitch revised its outlook last week on Aramco to negative from stable, after making a similar change for the Saudi government

Updated: 11-25-2020

Exxon Documents Reveal More Pessimistic Outlook For Oil Prices

The oil giant has lowered its expectations for prices for much of the next decade, internal documents reviewed by The Wall Street Journal show.

Exxon Mobil Corp. has lowered its outlook on oil prices for much of the next decade, according to internal company documents reviewed by The Wall Street Journal.

As part of an internal financial-planning process conducted this fall, Exxon cut its expectations for future oil prices for each of the next seven years by 11% to 17%, according to the documents.

The sizable reduction suggests the Texas oil giant expects the fallout from the coronavirus pandemic to linger for much of the next decade. The fossil-fuel industry is also contending with increased competition from renewable-energy sources and electric vehicles, as well as the prospect of increased climate-change regulation around the world.

Unlike some rivals, Exxon doesn’t publish its internal views on commodity prices, which it views as proprietary. Some investors have pressured Exxon to release them, arguing that the forecasts are critical to understanding a company’s plans and the future value of its assets.

In 2019, Exxon had internally forecast that Brent oil prices, the global benchmark, would average around $62 a barrel for the next five years before increasing to $72 a barrel in 2026 and 2027, the documents state.

This summer, the company lowered that forecast to between $50 and $55 a barrel for the next five years, before eventually topping out at $60 a barrel in 2026 and 2027, according to the documents, which were dated September.

Brent oil is currently trading for about $47 a barrel after a jump in prices this week that has brought prices back to their highest levels since spring.

Exxon’s new price forecast was used at an early stage of modeling its financial plan, which the company’s board was set to vote on this month, according to an Exxon executive. An Exxon spokesman declined to say what its current price projections are, saying that the company uses a range of prices to develop its business plans.

Years of lower oil prices threaten to put further financial pressure on Exxon, which has posted three straight quarterly losses this year for the first time on record, and before the pandemic was in the midst of a plan to spend $230 billion to pump an additional one million barrels of oil and natural gas a day by 2025.

While Exxon doesn’t disclose its forecasts, it has sounded upbeat in public statements about the long-term future for the oil industry coming out of the pandemic.

The company told investors in October that current underinvestment in oil and gas production would leave the world short of needed fossil fuels in coming years. In a note published on Exxon’s website in October, Chief Executive Darren Woods called the industry’s woes temporary and said that the need for Exxon’s products would increase in the near future.

“Even accounting for the short-term demand impact of Covid-19, the investment case is still clear,” Mr. Woods wrote.

Stephen Littleton, Exxon’s head of investor relations, said Exxon evaluates capital investment over a decadeslong time horizon, and that the coronavirus hadn’t changed its long-term view. Exxon hasn’t canceled any projects because of the pandemic, only delayed them, he said.

“The fundamentals haven’t changed; the only thing that has changed is timing, because we know populations and prosperity will increase,” Mr. Littleton said in an interview.

Exxon is struggling to cover its dividend, $15 billion a year, at current oil prices, taking on debt this year to do so. So far it has maintained the payout, unlike rivals including Royal Dutch Shell PLC and BP PLC, which have cut their dividends amid this year’s cash crunch.

The company cut $10 billion from its capital expenditures after the pandemic took hold and has said it could lay off as much as 15% of its global workforce, which would total about 14,000 jobs including contract employees. Exxon also said it would reduce its capital budget to between $16 billion and $19 billion next year.

Even with those cuts, Exxon would need oil prices to be between $55 and $65 a barrel in 2021 to cover its capital expenses and dividend, various analysts estimate.

Shell publicly lowered its price forecasts in June, predicting Brent oil would reach $50 a barrel in 2022 before reaching a long-term price of $60. As a result of that revision, it said it would write down the value of some oil and gas assets by as much as $22 billion. BP has also cut its price forecasts and written down billions in assets.

Exxon said in October that it might write down the value of natural-gas assets valued at as much as $30 billion, but said that doesn’t indicate changes to its long-term price views.

In recent decades, the company has seldom written down the value of any assets. Executives have for years argued that the company is extremely conservative with its investment decisions, choosing projects that will work financially in any commodity-price environment.

But Exxon’s status as a low-cost operator has slipped in recent years. Biraj Borkhataria, an analyst at RBC Capital Markets, said Exxon’s break-even is the worst among its peers and that, at current spending levels, its oil and gas production is poised to shrink.

Mr. Woods told investors in March that Exxon had stressed-tested a range of commodity prices, including low-price scenarios. If oil prices were to remain around $50 a barrel for years, a scenario Mr. Woods then called unlikely, Exxon’s debt levels would still be manageable.

“I would also tell you, if we found ourselves in this unprecedented environment for five years, we would change our plans,” Mr. Woods said.

Updated: 11-29-2020

OPEC Faces Seismic Demand Split As Cartel Plots Next Move

As OPEC+ ministers gather virtually this week, the city that traditionally hosts their meetings will be locked down. Vienna’s Christmas markets will be closed, the famous Ringstrasse boulevard silent. For oil ministers, the scene should urge caution.

But while the Austrian capital provides a dramatic example of how the second wave of the pandemic is shutting down economies in Europe and the U.S., the global picture is more nuanced.

In Asia, the situation is almost the opposite to that of Vienna. The streets in India were full during the recent celebration of Diwali; China’s Golden Week holiday saw millions take cars, trains and even planes to visit relatives across the country.

The east-west divide is an added conundrum for OPEC+, which on Monday and Tuesday needs to decide whether to delay a production increase slated for January — and if so, for how long. Informal talks on Sunday failed to yield an agreement.

As well as the geographical split, there’s another crucial divide in the global oil market: while gasoline and diesel demand have recovered to about 90% of their normal level, consumption of jet fuel languishes at about 50%.

“The size of the shock and the unevenness of its impacts imply a recovery process which is far from smooth,” said Bassam Fattouh, the head of the Oxford Institute for Energy Studies.

In private, OPEC+ delegates talk about the imbalance in the recovery, both geographically and between refined products. Increasingly too, they talk about another segmentation: crude oil quality. The market for the denser more sulfurous crude, called heavy-sour, is tight, mostly due to production cuts from Saudi Arabia, Russia and other big producers.

But the market for so-called light-sweet is glutted, in part because Libyan barrels have come back to the market after a ceasefire, and European refiners are consuming less North Sea crude.

All those factors make the deliberations of OPEC+ ministers trickier. And they have just one blunt tool at their disposal: raising or cutting overall production. OPEC+ nations do not target gasoline or jet-fuel production, but just crude.

There’s also a geographical handicap: most of their oil goes to Asia, where demand is strong, rather than Europe and America, where it’s weaker. That means they can do little to address the glut where it matters.

Even the quality is a problem: OPEC pumps mostly heavy-sour crude, and can do relatively little to trim the excess of light-sweet crude.

There is some consolation. While the recovery in oil demand that started in May stuttered in October and November as the second wave took hold, it wasn’t the same hit to the market as earlier this year. The lockdowns in Europe aren’t as severe as the first wave, and demand in Asia is surging — not just in China, but also in India, Japan and South Korea.

High frequency data for road usage shows a decline in early November of about 30% from pre-Covid levels, compared to nearly 70% in late March and early April, according to an index compiled by Bloomberg News. The most recent data suggests that road fuel demand bottomed out around Nov. 15, and has been recovering since.

With European nations easing lockdowns in the run-up to Christmas, demand is likely to recover further.

Pieced together, this all means the market isn’t as bad as it looked just a few weeks ago. Oil prices are reflecting the more positive tone: Brent crude has rallied well above $45 a barrel, and the shape of the curve has flipped, with nearby contracts trading at a premium to later ones. That dynamic, known as backwardation and traditionally a bullish signal, means that demand is running above supply.

The physical market, where actual barrels change hands, is also showing signs of strength: the favorite crude varieties of Chinese refiners are commanding rising premiums. Take ESPO crude of Russia, a grade that Chinese independent refiners, known as teapots, like to buy. In the most recent tenders, it has changed hands at $2.85 a barrel above its benchmark, up from 55 cents in mid-October.

Beyond the next quarter, the outlook improves further.

Many are already hopeful about the impact of virus vaccines on oil demand. If they are right, by mid-year, when OPEC is likely to be meeting again, the streets of Vienna will be once again full of tourists, often perplexed to see oil ministers followed by packs of television cameras across the Austrian capital. The cartel is tentatively planning to hold its bi-annual international oil seminar, a two-day festival of the industry, at the Imperial Hofburg Palace in June 2021.

“Vaccine efficacy and availability point to a large enough recovery in oil demand next year to allow OPEC to achieve both a rebalancing of excess inventories as well as increase production sharply,” said Damien Courvalin, oil analyst at Goldman Sachs Group Inc.

For now though, OPEC+ still has work to do. If the cartel wants to keep draining inventories accumulated earlier this year, it needs to keep the market in deficit, rather than simply balance supply and demand.

With Libyan output surging back, OPEC’s own economists believe that global inventories would increase by about 200,000 barrels a day during the first quarter of 2021 if the group increases output as scheduled in January.

If it delays the hike by three months, then stocks would instead drain by about 1.7 million barrels a day between January and March, a similar amount to what it expects in the fourth quarter of 2020.

“The job is far from done,” said Gordon Gray, global head of oil and gas equity research at HSBC Holdings Plc.

Updated: 11-30-2020

Troubles In The Oil Patch: Low Prices To Lost Jobs

Despite a recent oil rally, energy companies are riding out a historic downturn. Collectively, they have lost more market value, on a percentage basis, than any other major sector this year.

Oil prices briefly went negative. Exxon Mobil Corp. was booted from the Dow Jones Industrial Average. Pioneering fracker Chesapeake Energy Corp. succumbed to bankruptcy.

By some measures, the pandemic hit the energy industry harder than any other major segment of the U.S. economy in 2020. While crude prices have staged a rally in recent weeks, the sector is still going through one of the most brutal years in its history.

Producers scrambled to shut in wells and halve investments in the oil patch. Thousands of oil workers lost their jobs. Dozens of companies sought chapter 11 protection from creditors, while others sold themselves for little more than their diminished market value.

A key index of oil and gas producers and other energy firms continues to lag behind the S&P 500. Oil-and-gas companies collectively lost more market value, on a percentage basis, from the beginning of the year than any other major sector, including commercial airlines and hotels.

Here is a look at the troubles in the oil patch.

Weak Merger Market

While many investors and analysts believe consolidation is needed in the industry, few buyers are lately willing to pay a premium for oil-and-gas companies. The premiums buyers have paid for such companies over their market value fell after oil crashed in 2015 and haven’t really bounced back since. This year, they dropped further, to an average of about 8%.

Low Market Values

Even after the recent rally, the collective market capitalization of the 25 largest U.S. oil-and-gas companies has dropped about 32% since the end of last year, to about $574 billion, according to data from S&P Global Market Intelligence. That is down from $1.17 trillion at the end of 2013, close to the peak of the decade’s oil boom.

Rising Bankruptcies

This year, 43 North American oil-and-gas producers filed for bankruptcy through October, in cases involving $53.9 billion in total debt, according to the law firm Haynes & Boone LLP.

Idled Rigs

The U.S. rig count, an indicator of oil-field activity, has increased slightly in recent months. Energy companies have put 76 drilling rigs back to work since mid-August, according to oil-field services company Baker Hughes Co. At 320 active units, that is still less than half of the 793 they had running in early March, before statewide lockdowns.

Lost Jobs

Employment in support activities for oil and gas has dropped by one-fourth since January, according to the Bureau of Labor Statistics, as oil-field work disappeared in the pandemic. That sector has lost almost half of its jobs since early 2015. In oil-and-gas extraction, employment was essentially flat in 2020 but is down about 20% compared with January 2015.

Sluggish Prices

Oil prices have surged in November and stood around $45 per barrel this past week, their highest levels since spring. Still, while oil producers in some areas of the Permian Basin of West Texas and New Mexico can break even at such prices, most U.S. shale regions require higher prices, data from the consulting firm Rystad Energy shows.

Updated: 11-30-2020

Exxon Slashes Spending, Writes Down Assets

Battered by three straight quarterly losses, oil giant pulls back from CEO Darren Woods’s aggressive plan to increase production by 2025

Exxon Mobil Corp. XOM -5.13% is retreating from a plan to increase spending to boost its oil and gas production by 2025 and preparing to slash the book value of its assets by up to $20 billion, as the struggling company reassesses its next decade.

The Texas oil giant, which has lost more than $2.3 billion over the first three quarters of this year after the coronavirus wreaked havoc on fossil-fuel demand, released a reduced spending outlook Monday for the next five years.

It now plans to spend $19 billion or less next year and $20 billion to $25 billion a year between 2022 and 2025. It had previously planned to spend more than $30 billion a year in capital expenditures through 2025.

Exxon also said it would stop investing in certain natural-gas assets and telegraphed a massive write-down of between $17 billion and $20 billion to come in the fourth quarter.

The cuts are a course correction for Chief Executive Darren Woods, who laid out a plan in 2018 to spend $230 billion to double profits and pump an additional one million barrels of oil and gas a day by the middle of the next decade. That plan proved ill-timed, especially after the pandemic caused oil prices to plummet this spring.

Exxon said Monday it would now double its profits by 2027 but released no specific target for increasing its oil and gas production. Exxon executives have said in recent months that the company is reassessing its production targets.

Mr. Woods said in a statement that the company is focused on improving its earnings and strengthening its balance sheet to manage future price swings and maintain its dividend, which costs Exxon about $15 billion a year.

Exxon said in October that it plans to cut as much as 15% of its global workforce, which includes contract and full-time employees.

Exxon cut its expectations for future oil prices for each of the next seven years by 11% to 17% as part of a financial-planning process conducted this fall, The Wall Street Journal reported last week, citing internal documents. The sizable reduction suggests Exxon expects the economic fallout from the pandemic to linger for much of the next decade.

Exxon’s growth plan had set it apart from rivals that have pared back spending in recent years amid stubbornly low commodity prices. Even before the pandemic, the fossil-fuel industry was contending with an oversupply of oil and gas unleashed by U.S. frackers as well as increased competition from renewable-energy sources and electric vehicles and the prospect of increased climate-change regulation around the world.

Exxon would have to fundamentally remake itself to prosper in a prolonged period of lower oil prices, according to Doug Terreson, an analyst at investment bank Evercore ISI. But investors would welcome a permanent turnaround from its growth aspirations, he said.

“The market is indifferent as to whether they are larger or smaller. Investors want them to be more valuable,” said Mr. Terreson.

Exxon said Monday it would now place priority on investing in Guyana, where it made one of the largest oil discoveries of this century, and in the Permian Basin in West Texas and New Mexico, the largest U.S. oil field. The company also said it would focus on oil discoveries in Brazil and on its chemical business.

Exxon’s three straight quarterly losses this year are its worst stretch on record. Its share price has fallen about 16% over the last six months, the most among similarly sized oil-and-gas companies. Its shares closed at about $38 Monday.

Exxon had also stood out among its peers this year for resisting large write-downs. Its disclosure Monday that it could take a huge one comes after months of pressure from analysts and others who argued it needed to do so.

Royal Dutch Shell PLC said earlier this year it would write down the value of its assets by up to $22 billion, and BP PLC is writing down as much as $17.5 billion. Last year, Chevron Corp. said it would cut the value of its assets by $10 billion. All three companies cited internal forecasts for lower commodity prices as the cause of the impairments.

Exxon said its potential impairment isn’t related to any changes to its long-term price views or a reaction to short-term price fluctuations. Instead, the company said it has been strategically evaluating which assets are worth investing in under current market constraints, a process that has resulted in the spending cuts announced Monday.

The primary projects from which Exxon decided to withhold investment are dry gas assets in the U.S. and Canada as well as properties in Argentina. According to Exxon, because those assets now have no future cash flows due to canceled investment in them, the assets must be impaired. The company also said it would explore selling the assets.

Most of the properties in question are a part of Exxon’s subsidiary XTO Energy Inc., a natural-gas driller it purchased for $31 billion a decade ago. Several oil-and-gas accounting experts have alleged in a series of complaints filed to U.S. authorities that Exxon’s reluctance to adjust the value of XTO and other assets on its balance sheet amounts to accounting fraud.

The group, which filed a whistleblower complaint with the Securities and Exchange Commission in 2015, estimates Exxon should have taken a $44 billion impairment loss this year and a corresponding $56 billion reduction of its reported assets on its balance sheet in the second quarter.

The SEC previously declined to comment.

Exxon has rejected criticism of its write-down practices, saying it is complying with accounting rules and SEC regulations about disclosures to investors.

The oil giant has said it is able to avoid write-downs because it is extremely conservative in initially booking the value of new fields and wells and doesn’t respond to short-term commodity-price fluctuations. Before 2016, Exxon had never recognized an asset impairment under U.S. accounting rules implemented in the 1990s.

When Exxon announced its plans to acquire XTO in December 2009, the company’s second-largest deal ever, U.S. natural-gas prices averaged $5.35 per million British thermal units. But over the past five years, gas prices have mostly stayed below $3/MMBtu.

“We probably paid too much,” former Exxon Chief Executive Rex Tillerson said of the XTO deal at a conference last year, citing natural-gas prices.

Updated: 12-03-2020

U.S. Oil Production Doesn’t Grow At $45 A Barrel, BNEF Says

U.S. benchmark oil prices will need to trade in a range of $35 to $45 a barrel next year just to keep production flat, according to a new report by BloombergNEF.

The report highlighted different estimates needed to keep output steady from the major oil plays. For the Permian and Eagle Ford, companies need oil at $35 to $40 a barrel. Meanwhile, the Bakken needs prices in the region of $40 to $45 while Denver-Julesburg probably requires about $45 a barrel.

Up until last week, West Texas Intermediate hadn’t settled above $45 a barrel since early March as the pandemic all but crushed demand. Faced with unprecedented pressure from investors to return profits to shareholders, the industry is in cost-cutting mode.

For an explorer to turn a profit in the Permian’s Delaware, the lowest-cost U.S. basin, a current oil price of $33 a barrel is required, down from $40 in 2019, the release showed. So-called breakevens refer to the cost of bringing supplies online that’s less than or equal to the expected revenue.

“Contract renegotiations, ongoing efficiency gains and process improvements have allowed the oil industry to slash the cost to drill and complete a well,” according to the report. “Most U.S. oil companies have also been able to lower their operating and administration expenses.”

U.S. oil output is expected to close out next year at about 11 million barrels a day, about the same as it is now, based on forecasts from IHS Markit, Rystad Energy, Enverus and the U.S. Energy Information Administration.

Crude rose 1% to $45.71 as of 1:49 p.m. in New York on Thursday.

Updated: 12-04-2020

Chevron Slashes Spending Plans As Coronavirus Hammers Oil Demand

U.S. oil company follows rival Exxon in cutting annual outlays amid the pandemic.

Chevron Corp. said it would cut its annual capital spending budget by 26% next year and sharply through the middle of the decade, as the coronavirus pandemic forces an industrywide reappraisal of fossil-fuel investment.

Chevron said it would spend $14 billion next year and no more than $16 billion a year through 2025. It previously said it would spend $19 billion to $22 billion a year through 2024 before the pandemic.

The reductions by the U.S. oil giant follow those announced this week by rival Exxon Mobil Corp., which on Monday said it was reducing its yearly capital spending by about $5 billion to $10 billion each year through 2025. Exxon, which has lost more than $2.3 billion over the first three quarters of this year, also said it would slash the book value of its assets by up to $20 billion.

By some measures, the pandemic hit the energy industry harder than any other major segment of the U.S. economy in 2020.

Oil-and-gas companies collectively lost more market value, on a percentage basis, from the beginning of the year than any other major sector. Dozens of companies sought chapter 11 protection from creditors, while tens of thousands of oil workers have lost their jobs.

The sizable spending cuts by Exxon and Chevron this week mean that there will be even less work for the oil-field services companies that employ many of the industry’s ground-level workers, and that oil regions in many parts of the world will see reduced economic activity.

“Chevron remains committed to capital discipline with a 2021 capital budget and longer-term capital outlook that are well below our prior guidance,” Chevron Chief Executive Michael Wirth said in a statement.

In October, Chevron told investors it would spend around $14 billion in 2021 and indicated its long-term budget could be reduced as well. Chevron has lost nearly $5 billion this year, but unlike Exxon has managed to avoid taking on large amounts of new debt due to a relatively strong balance sheet. The company’s share price is down about 5% over the last six months and closed at $89.87 Wednesday.

Pierre Breber, Chevron’s chief financial officer, said the company’s spending plans represent an expectation of lower commodity prices over the next five years.

“It also reflects that we are an industry performing poorly relative to other investment opportunities,” Mr. Breber said. “Everything [Chevron is] looking at is through the lens of capital discipline and generating higher returns.”

Covid-19 has gutted demand for oil and gas as automobile and plane travel declined sharply amid global lockdowns and other measures to contain the virus. Chevron has let its production slide due to the weakened demand, choosing to give priority to directing its cash flow to dividend payments. It reiterated Thursday its commitment to its dividend.

Even before the pandemic, the fossil-fuel industry was contending with an oversupply of oil and gas unleashed by U.S. frackers, increased competition from renewable-energy sources and electric vehicles, while also contending with the prospect of increased climate-change regulation around the world.

Updated: 12-21-2020

Fracking: From Breaking Shale To Breaking Even

Understanding the mechanics and economics of fracking can help investors understand the dizzyingly cyclical nature of energy markets.

Everyone seems to have an opinion about fracking. The revolutionary and controversial oil-and-gas exploration technique has raised the ire of oil sheikhs, investors and environmentalists while minting billionaires and wiping out tens of billions of dollars fronted by many of their lenders and investors.

But What Exactly Is It?

Fracking is shorthand for hydraulic fracturing, a drilling method that involves injecting water, sand and chemicals under high pressure through a well. The high pressure of all the components causes rocks to fracture and the sand keeps those fissures open, while the chemicals help ease the oil or gas out.

The method itself has been around for decades, but the more recent development is the pairing of hydraulic fracturing and horizontal drilling.

This has allowed companies to start extracting oil and gas from less-permeable rocks such as shale, opening up vast new fields collectively called unconventional reservoirs. Conventional reservoirs, where extraction widely took place before the fracking boom, involve tapping into more permeable, spongier rocks, such as limestone, from which oil and gas flows, usually without artificial pressure.

Fracking has been groundbreaking for the U.S. and the world. Up until 2000, U.S. onshore oil-field development had stalled; fracking breathed life back into hydrocarbon production. In September 2019, the country became a net monthly exporter of crude oil and petroleum products for the first time since the U.S. Energy Information Administration started keeping monthly records in 1973.

It also meant that the business of exploration became less speculative and almost like an assembly line. “With the new technology, all of a sudden your chances of being unsuccessful went way down,” notes Dan Pickering, founder of Pickering Energy Partners. “The odds that you found oil were 90% instead of 30%.”

That certainty comes at a price. Today, the West Texas Intermediate price at which a U.S. producer can drill a new well profitably—its break-even point—is roughly $49 a barrel, according to the Kansas City Federal Reserve, which is a good approximate proxy for fracking since most U.S. production happens using that method.

That isn’t the most expensive barrel that can be produced profitably—many established offshore fields or onshore oil-sands deposits are pricier—but it is far dearer than drilling by the big, traditional oil exporters whose economies have been shaken by the fracking boom.

A new well in Saudi Arabia can break even at a Brent crude oil price of less than $20 a barrel on average, according to Saudi Aramco, and an existing well breaks even below $10 on average.

While members of the Organization of the Petroleum Exporting Countries still collectively produce more oil more cheaply than anyone else, fracking has wrecked their pricing power. Whenever OPEC has cut back on its supply to prop up prices, U.S. producers have tended to jump in to fill the gap.

A 2019 study from the Dallas Fed found that long-dated oil futures have closely tracked the break-even price for U.S. oil producers since 2014. The U.S. has become the marginal producer when it comes to meeting long-term demand.

One problematic aspect of fracking is its quick decline rate. Drawing oil and gas out of a conventional well is much like slowly pouring soda out of a can. Fracking looks more like what happens when you shake the can and open it. Hydrocarbons come out quickly but start losing momentum rapidly, too.

Production in the Eagle Ford oil field in Texas, for example, declines 60% in a well’s first year and more than 90% over the first three, according to a study from the Kansas City Fed. Conventional oil fields register decline rates of just 5% to 10% a year.

But a well can be fracked in months, not years. That short-cycle nature partly explains the way producers have conducted business. Energy companies, particularly publicly listed ones, have had to constantly drill new wells to maintain steady production. In many cases, they racked up substantial debt to fund new drilling, risking bankruptcy at times of depressed oil or gas prices. Hundreds of small firms and some big ones like Whiting Petroleum and Chesapeake Energy saw shareholders wiped out.

Of course, cycles are nothing new to the industry. Over the years, oil-price collapses have led to the demise of smaller, less well-capitalized firms, either through bankruptcy or consolidation. As a result, fracking increasingly is dominated by deep-pocketed players such as Exxon Mobil and Chevron.

Oil-price collapses often spur efficiency gains. The last time this happened in a dramatic way was between 2014 and 2016, when break-even prices dropped from $79 a barrel to $53, according to the Kansas City Fed. The side effect is stress on the ecosystem supporting frackers such as oil-field-services companies and more pressure on OPEC.

Frackers have repeatedly claimed to be more disciplined than in the past. Conventional producers have, too, almost as long as there has been an oil business. Booms and busts aren’t going away but fracking, despite its short time on the energy industry’s center stage, might have changed them permanently. Peaks and valleys are now more frequent.

Combine that with high costs and easy money and it is clear that this short-cycle industry could do with a longer-term memory, including from its investors.

Shell Signals Another Poor Quarter For Oil Majors

Energy giant warns of third-consecutive quarterly loss for its oil-and-gas production business, and a further write-down.

Royal Dutch Shell RDS.A -4.72% PLC said it would write down the value of its assets by up to $4.5 billion and warned of another set of poor earnings for the fourth quarter, showing how the oil-and-gas industry continues to struggle amid the fallout of the pandemic.

The energy giant said Monday its oil-and-gas production business would likely report a third consecutive loss in the last three months of the year, and that results from its trading operations—a bright spot earlier in the pandemic amid volatile oil prices—would be below average.

Shell’s update is the first indication of another tough quarter for the oil-and-gas sector, which continues to grapple with lower demand as Covid-19 lockdowns hit economies hard and halt travel around the world.

The downbeat trading update, issued ahead of fourth-quarter earnings due in February, comes despite a recovery in oil prices in recent weeks after vaccines to fight the virus were approved in some countries. Benchmark Brent oil has stabilized and reversed some losses, gaining almost 20% in the past three months to trade at around $50 a barrel, having briefly traded below $20 a barrel in April.

However, while Shell noted improved refining and chemical margins compared with the previous quarter, the rising oil price doesn’t appear to have been enough to turnaround the company’s fortunes.

“The indicative guidance looks disappointing,” said Biraj Borkhataria, an analyst at RBC Capital Markets.

Shell said the flagged $3.5 billion to $4.5 billion write-down includes an impairment of its deep water oil-and-gas project Appomattox, in the Gulf of Mexico, as well as charges related to its refining operations and onerous gas contracts.

The accounting charge follows the $16.8 billion posttax write-down Shell took earlier in the pandemic due in part to lower energy prices.

The pandemic has also prompted the company to reassess its payout to shareholders, with Shell cutting its dividend for the first time since World War II in April. The company did, however, increase its dividend slightly last quarter.

Shell has also sought to sell assets to shore up its finances and reduce its debt, which stood at around $73.5 billion at Sept. 30.

The company said Monday it had continued that drive, selling a 26.25% stake in infrastructure related to its Queensland Curtis LNG project to Global Infrastructure Partners Australia for $2.5 billion. The facilities include liquefied natural gas storage tanks, jetties and operations infrastructure. Shell expects the deal to complete in the first half of next year.

Shell previously said that it expects divestment proceeds to average $4 billion a year.

The oil major is also in the midst of a restructuring as part of a broader plan to accelerate investments in low-carbon energy, details of which are expected at a strategy update in February.

Shell said in September it was cutting up to 9,000 jobs as part of the restructuring, which it has indicated will focus on the highest value oil it produces, and growing its liquefied-natural gas and low-carbon energy businesses, while shrinking its refining operations.

That would follow a similar move by BP PLC, which is cutting 10,000 jobs or 14% of its workforce, alongside a plan to reduce its dependence on oil and increase low-carbon energy investments. Major oil companies including Shell and BP say the pandemic could accelerate the shift to cleaner energy.

Updated: 1-17-2021

Oil-and-Gas Industry Faces A Slow Recovery From Pandemic Lows

Spending on oil production world-wide isn’t expected to climb back up to pre-pandemic levels through at least 2025.

Oil and gas prices are rebounding from their pandemic lows, but the road ahead for the industry remains challenging amid new competitive threats and demands from investors.

Global spending on oil and gas production is poised to remain below pre-pandemic levels through at least 2025, according to consulting firm Wood Mackenzie, as companies face pressure to improve returns and reduce their greenhouse-gas emissions.

Meanwhile, investment in renewables and other clean energy technologies is taking off, threatening to eat into the market for oil and gas long-term.

Though oil prices have notched gains since November, they’re expected to remain below levels that support attractive returns, particularly for an industry still recuperating from last year’s historic drop in fuel demand.

As a result, companies aren’t rushing back into drilling. A third of oil producers surveyed by the Dallas branch of the Federal Reserve in the fourth quarter said they planned to raise capital expenditures only slightly this year. About half said they would either keep spending flat or reduce investments.

Exxon Mobil Corp. and Chevron Corp. cut plans to invest a combined $260 billion through 2025 to as low as $177 billion.

Over the next five years, global oil spending is projected to come to a little more than half of what companies invested in the first half of the 2010s, according to Wood Mackenzie. Last year, the pandemic had brought oil investments to the lowest levels since 2005.

The slowdown comes as investors explore alternatives such as solar and wind power, which have seen costs drop dramatically in recent years, and emerging technologies such as battery storage and biofuels.

Energy investment outside of fossil fuels, including renewables and other clean-energy technologies, is set to attract 60% of the world’s energy investment in this decade, according to the International Energy Agency.

Non-fossil-fuel investments will climb to an annual average of $1.4 trillion, the IEA says, higher than the $935 billion it has projected for oil, natural gas and coal. In the 2030s, it says, those investments will make up roughly two-thirds of energy spending.

The projected shift in investments means that, after decades dominated by fossil fuels, renewables are poised to gain ground.

By 2030, noncarbon energy—including nuclear, wind and solar—is expected to climb to almost 13% of the world’s energy demand from 9.8% in 2019, according to IHS Markit. Last year will be the first in which clean energy surpassed 10% of demand, the consulting firm projected, in data going back to 1990.

Whether this spending shift affects consumers in the next few years is uncertain, but some believe oil companies will eventually have to increase spending to meet global demand in coming decades.

The International Energy Forum, a group advising energy importing and exporting countries, says the oil industry’s capital expenditures need to climb by $225 billion from last year’s levels by 2030 to prevent a fuel-price spike that would be damaging to economic growth. It warned that “peak investment,” in which oil spending stays lower than 2019 levels for good, was a more pressing post-virus issue than peak oil demand.

Meanwhile, the consulting firm Rystad Energy said in a recent analysis that it would take 80 years to find sufficient supplies to meet global demand through 2050 at the past decade’s low level of exploration activity.

For now, though, American drivers aren’t giving oil companies much reason to change course. Household spending on gasoline in the U.S. is projected to edge upward this year but remain well below 2017-19 levels, according to fuel-price tracking site GasBuddy.

Another reason oil companies will keep spending at lower levels is that electric vehicles are expected to skyrocket to about 32% of new vehicle sales globally in 2030, up from less than 4% last year, according to Deloitte, which made the forecast before a recent uptick in auto sales. In China, they will rise to 48%, and in the U.S. to 27%, Deloitte projects.

Updated: 1-18-2021

Oil Giant Total Buys Stake In World’s Biggest Solar Developer

French energy company to pay $2.5 billion for 20% of Adani Green Energy.

French energy giant Total SE said it would pay $2.5 billion for a 20% stake in the world’s largest solar developer, the latest move by an oil major to expand in renewable power.

Total said Monday the investment in Adani Green Energy Ltd. would help it meet its targets for generating more power from low-carbon sources amid a continuing global transition away from fossil fuels—a shift some analysts say is being accelerated by the pandemic.

The company, along with other oil majors including BP PLC and Royal Dutch Shell PLC, has pledged to increase spending on renewable energy such as wind and solar power in an effort to reduce carbon emissions. Total plans to spend $3 billion a year on renewables by 2030, around 20% of its annual investment budget and up from $2 billion last year.

The Adani deal gives Total exposure to a leading renewables business in India, one of the world’s fastest-growing markets for energy demand. Adani has 54 wind and solar projects in operation across the country, including one of the world’s largest solar projects in Kamuthi, Southern India. Based on existing generating capacity and the projects in its pipeline, Adani is the world’s largest developer of solar power, Total said.

As part of the deal, Total is also taking a 50% stake in a portfolio of Adani’s solar assets and getting a seat on the company’s board. The move will help Total toward its goal of having 35 gigawatts of renewable power capacity by 2025, up from around 7 gigawatts last year.

“Given the size of the market, India is the right place to put into action our energy transition strategy based on two pillars: renewables and natural gas,” said Total Chief Executive Patrick Pouyanné.

Total and Adani Group, one of India’s largest infrastructure conglomerates, have previously made other joint investments, including in liquefied-natural gas.

Major oil companies have boosted their activities in renewable energy in recent years, anticipating that demand for oil will eventually decline, as more of the global economy becomes electrified. New technologies such as electric vehicles, for example, are expected to increase demand for electricity, while denting requirements for oil-based transport fuels such as gasoline and diesel.

Monday’s deal isn’t the first time Total has invested in solar. In 2011, the company bought a majority stake in U.S. solar panel manufacturer SunPower Corp. However, following several years of losses, SunPower spun off its panel-making business in August to focus on solar-panel installations. Total remains a shareholder in both SunPower and the new Singapore-based company Maxeon Solar Technologies Ltd.

Other major oil companies have also invested in the solar industry. BP took a stake in Lightsource Renewable Energy in 2017 and has since boosted its holding. The same year, Shell invested in Singapore-based Sunseap Group Pte Ltd., followed by an investment in Cleantech Energy Corporation Pte Ltd.’s solar business in 2018.

Updated: 1-22-2021

Cancelled Keystone XL Pipeline May Yield 48,000 Tons of Scrap

The scrapping of Keystone XL not only means the end of multibillion-dollar pipe dream for TC Energy Corp. — it also leaves behind 48,000 tons of steel.

U.S. President Joe Biden revoked permits for the oil pipeline on his first day in office, killing a cross-border project that had won a four-year reprieve under his Republican predecessor, Donald Trump. The pipeline would have spanned almost 1,900 kilometers (1,180 miles). TC Energy anticipated needing about 660,000 tons of steel just for the U.S. portion.

About 150 kilometers of pipe had been installed and an additional 2.2 kilometers had been completed at the Canada-U.S. border as of the end of 2020, the Canada Energy Regulator said in a Jan. 22 email. That would amount to nearly 48,000 tons of steel, assuming standard dimensions of line pipe, according to Bloomberg calculations based on industry criteria.

The benchmark steel price is about $1,060 a ton, which would value the haul at almost $51 million — though as scrap it would be sold for less. Secondary metal, which is any scrap that is already past use for its original purpose, sells at a discount to new forms of the raw material. Once sold, the scrap metal is remelted by the buyer and formed into new steel products.

TC Energy may to have to sell already delivered metal to secondary markets. While unclear exactly how much steel the Calgary-based firm owns that’s tied to Keystone — some may also be in storage — industry observers say it likely isn’t enough to make a dent on the market. The amount that could be sold would be a fraction of the total U.S. steel market demand of around 100 million tons a year.

TC Energy couldn’t be immediately reached for comment. A spokesman for the Canada Energy Regulator, which oversees the Canadian portion of the project, said no decisions have been made on the steel.

The regulator “continues to engage with TC Energy since the presidential permit for the Keystone XL Project was revoked,” the Canadian agency said in the statement, adding that it will “continue its regulatory oversight, focusing on ensuring safety and environmental protection.”

Updated: 1-23-2021

Oil Industry Reels As Biden Targets Fossil Fuels In First Days

Hours after taking office, President Joe Biden made good on a campaign promise to cancel the Keystone XL oil pipeline. Later that day his Interior Department mandated that only top agency leaders could approve new drilling permits over the next two months.

Next week, according to people familiar with the plans, Biden will go even further: suspending the sale of oil and gas leases on federal land, where the U.S. gets 10% of its supplies.

The actions sent oil producers’ stocks tumbling and raised blood pressure across the industry.

“In the first couple of days of the new administration, they are taking actions that will harm the economy and cost Americans their jobs,” said Frank Macchiarola, a senior vice president of policy for the American Petroleum Institute. “We’re concerned, and everyone in the country should be concerned.”

The Interior Department’s order, signed late Wednesday, changes procedures for 60 days while the agency’s new leadership gets into place. It requires top brass to sign off on oil leases and permits as well as decisions about hiring, mining operations and environmental reviews.

The industry took it as a bad omen. Officials are worried that technical permitting decisions are being placed in the hands of political appointees, rather than expert regulators in the field. And they’re concerned permits — or simply changes to them — will be delayed for existing drilling operations.

Moreover, many interpreted it as a prelude to broader actions, including the administration’s plan to next week impose a moratorium on all oil, gas and coal leasing across some 700 million acres (2.8 million hectares) of federal land.

This “announcement is intended as a temporary ban on leasing and permitting but is also a precursor to a longer-term ban,” said Kathleen Sgamma, head of the Western Energy Alliance, which has threatened to go to court to battle any such blockade.

While Biden’s campaign promises – and his initial moves to fulfill them – are a threat to some U.S. oil producers, the actions could be a boon for crude prices by restraining supply.

The administration’s early moves mark a dramatic shift from the course under former President Donald Trump, who sought to accelerate drilling permits and open up more places to oil exploration.

And the change in direction is already apparent in early staffing decisions. Under Trump, the top offshore drilling regulator at Interior was Scott Angelle, a longtime oil industry ally and former Louisiana official who pushed for rapid permitting of Gulf of Mexico oil projects after the 2010 Deepwater Horizon disaster.

By contrast, one of Biden’s first hires at the Bureau of Ocean Energy Management that oversees offshore oil leasing and wind farms is Marissa Knodel, a former activist with Friends of the Earth. Knodel was one of about 150 people whose rowdy protest of a bureau auction of oil drilling rights in March 2016 prompted the agency to shift subsequent oil and gas lease sales online.

On the campaign trail, Biden called for phasing out fossil fuels and promised to halt new oil and gas permitting on federal land. Worried oil producers stockpiled leases and drilling permits last year in anticipation of more restrictions under Biden.

But the suddenness of this week’s moves still took many in the industry by surprise, prompting frantic phone calls as lobbyists and lawyers sought to plan their next moves. They are strategizing their options, including litigation, and looking at any political levers they can pull to forestall a broader leasing ban.

Senator Dan Sullivan, a Republican from Alaska, said permitting changes threaten operations in his state during the current winter season, when companies such as ConocoPhillips rely on ice roads and ice pads to support drilling and other activity in the National Petroleum Reserve-Alaska.

“If you put a 60-day moratorium on drilling in the NPR-A, guess what? You lose the whole season,” Sullivan said Friday on the Senate floor.

Environmentalists are delighted. They say throttling fossil fuel development on federal land is necessary to pare the greenhouse gas emissions driving climate change. The oil, gas and coal extracted from federal lands and waters is responsible for about 24% of U.S. carbon dioxide emissions, according to a U.S. Geological Survey report.

“Pausing new fossil fuel decisions brings us closer to healthier communities, a healthier climate and healthier wild places,” said Dan Ritzman, director of Sierra Club’s Lands, Waters and Wildlife campaign. “Public lands can and must be part of the climate solution.”

Updated: 1-26-2021

Biden’s Climate Change Policy Targets Oil Industry

President to suspend new oil and gas leasing on federal land, setting stage for confrontation with energy sector.

The oil industry is emerging as a primary target of President Biden’s climate policy, setting the stage for a confrontation that could shape the future of the energy sector.

The president is expected to issue an executive order Wednesday that would suspend new oil and gas leasing on federal land, people familiar with the matter say, in what is widely seen as a first step toward fulfilling Mr. Biden’s campaign pledge to stop drilling on federal lands and offshore.

Drilling on federal lands accounts for roughly 9% of U.S. onshore production, but oil industry leaders see a curtailment on future development as a significant threat. Oil companies want to maximize their access to land and federal permits to help grow and sustain operations, and they plan to resist Mr. Biden’s efforts through lawsuits and lobbying Congress.

“The early actions of the administration are unilaterally shutting down and restricting the ability of American oil and gas producers to run their operations,” said Anne Bradbury, chief executive of the American Exploration and Production Council, which represents independent U.S. oil companies. “The scope and the lack of consultation with industry stakeholders has been alarming.”

In addition to a possible ban on new leases, Mr. Biden issued orders on his first day in office last week for a wide-ranging review of policies that former President Donald Trump had intended to ease restrictions on oil and other industry.

Mr. Biden revoked the permit for the Keystone XL pipeline from Canada and moved to stop oil companies from drilling in Alaska’s Arctic National Wildlife Refuge. No drilling has yet begun there, but the Trump administration had auctioned leases in the refuge earlier this month.

As a candidate, Mr. Biden had said climate change is one of the biggest crises the country faces, and that he would push the country to “transition away from the oil industry.” Through gasoline burned by cars and trucks, oil in recent years has become the country’s top source of the greenhouse-gas emissions that warm the planet, according to Environmental Protection Agency data.

Many of his actions have been expected, but the administration’s speed and willingness to target the industry have surprised its leaders and analysts. Share prices of U.S. oil companies tumbled in the week since these moves, stinging the industry at a time when it already faces existential questions from low prices and growing competition from cleaner sources of energy.

Mr. Biden has been under pressure from environmentalists to take aggressive action. Because of the oil industry’s history of contributing to climate change, they are cheering Mr. Biden’s steps as a way to limit its future role in U.S. energy.

“The temporary halt on new oil and gas leases is critical,” said Natalie Mebane, associate director of policy at 350.org, an advocacy group that wants to limit oil production. She called the orders an “important step to protecting our communities, lands, and waters, halting corporate pollution and giveaways to fossil fuel CEOs.”

Industry leaders say that is unfairly punitive and risky. Keystone XL’s developers laid off 1,000 workers immediately upon Mr. Biden’s move last week, and tens of thousands more could follow if oil companies can’t keep drilling on federal territory.

Industry leaders also say the moves endanger progress on emissions, which have fallen dramatically in the U.S. in recent years in part from a drilling boom that allowed power producers to burn more gas instead of coal.

Mr. Biden has promised to help laid off workers through promoting cleaner sources of energy. His climate plan includes $2 trillion in spending—grants, loans and tax incentives that would need to be approved by Congress—to help wind- and solar-power developers, battery makers and the electric-vehicle businesses that Mr. Biden says can employ more people in the future.

In addition to the moratorium on oil and gas leasing, Mr. Biden on Wednesday is expected to set a goal of protecting 30% of federal land and water by 2030, the people said.

The president is also planning to re-establish a White House council of science advisers created during the Obama administration. Mr. Biden’s plans were earlier reported by Bloomberg News and others.

Administration officials have discussed holding a climate change summit, possibly on Earth Day, April 22, one of the people said, but officials haven’t yet finalized those plans. Mr. Biden pledged during his campaign to convene a summit of leaders from around the globe to discuss climate change early in his administration.

The president has named climate change one of the four crises he hopes to tackle during his administration, along with the pandemic, the economy and racial inequality. The president tapped former Secretary of State John Kerry and former Obama Environmental Protection Agency Administrator Gina McCarthy to focus on international and domestic climate-change matters, respectively.

Mr. Kerry is the president’s special envoy for climate change and Ms. McCarthy is leading a newly formed White House Office of Domestic Climate Policy.

The expected executive order Wednesday to freeze new oil and gas leasing builds on actions Mr. Biden took during his first day in office. He put a moratorium on oil and gas leasing in Alaska’s Arctic National Wildlife Refuge, reversing Congressional action taken in 2017 to begin leasing in the area.

The Interior Department subsequently issued an order suspending all onshore and offshore fossil fuel-related authorizations for 60 days unless they are approved by the department’s senior leadership.

How much the Biden administration can limit access to offshore oil and gas, and drilling on federal lands, may ultimately be decided by the courts, according to the analysis firm ClearView Energy Partners LLC.

There are potentially conflicting laws that in some cases require the federal government to make federal territory available for drillers and miners, but in others may be interpreted as giving the president broad authority to limit what territory is available, Clearview says.

The consulting firm Rystad Energy says a de facto ban on new leasing is now reality, but that the oil industry has also insulated itself from immediate impact.

Oil companies used the final months of the Trump administration to stock up on permits. Federal permitting in New Mexico—a hotbed of Permian Basin drilling on federal land—more than tripled from 2017 to 2020; offshore permitting rose sharply starting in August, and by December had doubled from February, the firm said.

That will delay the biggest impacts for five years or more, the firm said. As current leases expire and exploration slows, annually the U.S. will lose upwards of 300,000 barrels of day in expected production, but peaking after 2031, according to Rystad’s estimates.

Updated: 1-29-2021

Chevron Posts Quarterly Loss To Cap Worst Year Since 2016

Like its peers, the oil giant endured a tough 2020 as the coronavirus pandemic crushed demand for fossil fuels.

Chevron Corp.  posted its third consecutive quarterly loss Friday to close its worst year since 2016, as the global pandemic continues to weigh on the oil-and-gas industry and cloud hopes for renewed economic growth in 2021.

Chevron is looking to turn the corner on one of the most painful years in modern history for oil-and-gas companies. The coronavirus sapped global demand for fossil fuels as the industry also faces longer-term challenges from the rise of electric cars, the proliferation of renewable energy and growing concern about the lasting impact of climate change.

The San Ramon, Calif.-based company is among the first of the energy giants to report their year-end results. For the fourth quarter, Chevron posted a loss of $665 million. For all of 2020, the loss totaled $5.5 billion; Chevron reported nearly $3 billion in profit for 2019.

“We’ve demonstrated that we can survive a year unlike any other and come through it even stronger,” Chief Executive Mike Wirth said in an interview. “Now we’ve got to come through this pandemic and see what the real state of the global economy is, and I think it’s going to be uneven.”

Chevron’s oil-and-gas-production unit posted $501 million in profit for the fourth quarter, but the results were weighed down by the refining and chemical businesses, as well as higher pension expenses and costs related to the $5 billion acquisition of Noble Energy last year. Analysts had expected Chevron to post a quarterly profit, and the company’s share price fell more than 4% Friday.

Chevron’s share price has fallen about 23% over the past year, a steep decline but better than many of its peers. Investors have expressed more faith in Chevron than rival Exxon Mobil Corp. because it entered the downturn with a stronger balance sheet.

Exxon had about $69 billion in debt as of September, while Chevron had around $35 billion, according to S&P Capital IQ.

Exxon is expected to report its quarterly results on Tuesday.

Chevron’s stock has been buoyed recently by oil prices climbing about 5% over the past month, as Brent crude, the global benchmark, rose more than 8% over the same period.

Oil traders have been shrugging off expanding coronavirus-related lockdowns in Asia and Europe, anticipating increased oil and gas demand in 2021 as vaccines are distributed, according to analyst Rystad Energy. Oil prices have also been boosted by Saudi Arabia’s pledge to cut another one million barrels a day of oil production in February and March.

Some analysts believe Chevron is poised for a much stronger year. The company could generate about $12 billion in free cash flow in 2021 if Brent oil prices are around $50 a barrel, according to JPMorgan Chase & Co., more than enough to cover its roughly $10 billion in annual dividend payments.

Chevron can now break even if oil is at $46 a barrel, said JPMorgan, after it made steep spending cuts and reduced its workforce in 2020. Last year, Chevron lowered its 2020 capital expenditures to $14 billion from $20 billion, and said it would spend between $14 billion and $16 billion annually through 2025. It had previously said it could spend as much $22 billion a year over that period.

The $665 million fourth-quarter loss compared with a loss of $6.6 billion during the 2019 period, which was driven by a roughly $10 billion write-down. Revenue fell to $25 billion in the 2020 quarter from about $36 billion.

Chevron leaned on its strong balance sheet to complete one of the largest oil-and-gas deals in 2020, its acquisition of Noble Energy, which was completed in October.

The company’s oil and gas production increased 1% in 2020 from the previous year to 3.08 million barrels a day, in part because Chevron added Noble’s output. Morgan Stanley estimates Chevron will produce nearly 3.3 million barrels a day in 2021.

Despite some optimism for an industry rebound in the coming year, long-term questions hover over oil-and-gas companies’ future profitability.

This week, S&P Global Ratings warned it could cut the credit rating of Chevron and many other major oil companies over growing risks to the industry from a transition to a lower-carbon economy spurred by concerns about climate change. Such a credit downgrade could increase borrowing costs for the sector, making it more difficult to finance large projects.

On Wednesday, President Biden issued an executive order temporarily suspending new oil and gas leases on federal land, which analysts said signaled a more restrictive U.S. policy outlook for the industry. About 25% of U.S. oil production is tied to federal lands and waters, according to Morgan Stanley, and Chevron has a large presence in both.

Mr. Wirth said the world is moving to a lower-carbon energy system and that Chevron’s strategy is to simultaneously lower its carbon footprint and generate higher returns. He said he supports President Biden’s desire to reduce carbon emissions, but said some of the executive orders were broad and risked erecting barriers to responsible energy development.

“The current energy system is not the enemy,” he said. “Emissions are what we should focus on.”

Updated: 2-2-2021

Oil Companies Endure Brutal 2020, Warn of Slow 2021 Recovery

Exxon, BP and others notched one of their worst annual performances as the pandemic crushed demand for fossil fuels.

The big international oil companies are reporting one of their worst annual performances in decades and signaling that the pandemic could continue to challenge their businesses in 2021.

Exxon Mobil Corp. and BP PLC on Tuesday disclosed annual losses of $22 billion and $18.1 billion respectively, following Chevron Corp., which on Friday reported a $5.5 billion loss for 2020.

Exxon posted its fourth consecutive quarterly loss for the first time in modern history, driven by a more than $19 billion write-down. Excluding the impairment, Exxon turned a quarterly profit of $110 million.

BP reported a replacement cost profit—a metric similar to the net income figure that U.S. oil companies report—of $825 million for the three months ended Dec. 31, from a loss of $4 million in the year-earlier period.

Covid-19 has sapped demand for oil, hitting prices and prompting the world’s biggest energy companies to slash spending, cut jobs and write down the value of their assets. Amid the crisis, Exxon and Chevron discussed a merger of the U.S. oil giants last year, according to people familiar with the matter, although the talks didn’t progress.

“The past year presented the most challenging market conditions Exxon Mobil has ever experienced,” said Chief Executive Darren W. Woods.

Exxon remains under pressure from a pair of activist investors. One of them, Engine No. 1 LLC, nominated four directors to Exxon’s board last week and called for it to make strategic changes to its business plan. On Tuesday, Exxon announced it had elected a new independent director to its board and is continuing discussions with other director candidates.

Engine No. 1 said the changes were insufficient.

“A board that has underperformed this dramatically and defied shareholder sentiment for this long has not earned the right to choose its own new members or pack itself in the face of calls for change,” Engine No. 1 said in a statement. “Exxon Mobil shareholders deserve a board that works proactively to create long-term value, not defensively in the face of deteriorating returns and the threat of losing their seats.”

BP said Tuesday that Covid-19 restrictions would continue to sap demand early in 2021 and that the pandemic might have an enduring impact on the global economy, with the potential for weaker demand for energy for a sustained period.

Still, Chief Executive Bernard Looney said the company expects demand to stabilize this year, although the speed and degree of the recovery is uncertain.

“It’s all dependent on vaccine rollouts, vaccine efficacy and OPEC compliance,” Mr. Looney said. Unlike its U.S. counterparts, BP hadn’t spoken to any of its peers about mergers, Mr. Looney said, adding that the company was focused on executing its strategy to pivot toward low-carbon energy.

BP’s shares traded 3.1% lower in London on Tuesday as the results came in below analysts’ expectations. Exxon was slightly up premarket Tuesday following its results.

Other oil companies are also feeling the strain. Royal Dutch Shell PLC reports Thursday and has telegraphed it will take a large write-down.

The pandemic has already triggered the largest revision of the value of oil-and-gas assets in at least a decade, as companies sour on costly projects amid the prospect of low prices for years. Exxon’s more than $19 billion write-down, primarily related to U.S. shale gas assets, is among the largest ever taken in the industry.

The Irving, Texas-based company cut nearly $12 billion from its 2020 capital expenditures and $8 billion from operating expenses in response to the pandemic and said Tuesday that it would trim operational spending by another $3 billion by 2023.

Exxon plans to spend as much $25 billion a year on capital expenditures through 2025, but said Tuesday that if Brent crude oil prices fall below $45 a barrel it could cut spending further. The company said it expects to cover its dividend, which costs it about $15 billion annually, from its cash flow in 2021, assuming Brent is $50 a barrel.

It was trading around $56 Tuesday.Activist investor Engine No.1 has argued Exxon should focus more on investments in clean energy while cutting costs elsewhere to preserve its dividend.

However, Exxon and rival Chevron haven’t set out plans to invest substantially in renewables, instead choosing to double down on oil and gas. Both companies have argued that the world will need vast amounts of fossil fuels for decades to come, and that they can capitalize on current underinvestment in oil production.

On Monday, Exxon said it would form a business unit focusing exclusively on technologies to reduce carbon emissions, investing about $3 billion through 2025, primarily on carbon-capture projects, which gather carbon emissions from industrial processes, or directly from the air, and deposit them underground.

BP has suggested that demand for fossil fuels might never fully recover and that the pandemic could accelerate the pace of transition to a lower-carbon economy. Under Mr. Looney, BP has embarked on a plan to reduce its dependence on oil and gas, while increasing investments in low-carbon energy like wind and solar power.

French energy giant Total has also outlined plans to build up its renewables business, while Shell has signaled its intention to set out a similar path later this month.

“An unprecedented demand collapse has forced the hand of Big Oil to right-size their dividends and capital frames; meanwhile plans for energy transition have been accelerated,” said Christyan Malek, an analyst at JPMorgan.

To bolster its finances, BP has been selling assets to reduce debt. The company said it was now more than halfway to its target of $25 billion of asset sales by 2025, helped Monday by the sale of a 20% stake in a gas development in Oman. BP aims to lower its debt to $35 billion by the first quarter of next year, down from $39 billion at the end of 2020.

Rebecca Fitz, a senior director at Boston Consulting Group, said she thinks both the European and American strategies can work, but both must deliver better returns and produce less carbon to be palatable to investors.

“When you have less capital, choices around how you allocate that capital are more stark,” Ms. Fitz said.

Updated: 2-5-2021

The End of Demand Isn’t the End For Big Oil

Producers may be worried because 150 years of uninterrupted growth have drawn to a close. The iron ore market may offer a lesson.

The oil market is taking reports of the death of crude surprisingly well.

Crude jumped to its highest level in more than a year Friday, on signs that inventories are declining amid a hoped-for recovery from Covid-19. Brent moved as high as $59.12 a barrel, within a whisker of the $60 level where swathes of the industry find it easy to balance their books.

There’s a lesson in all this from the second-most consumed commodity, iron ore, and how it has handled the ups and downs of the past decade. Many oil producers still see the end of 150 years of almost uninterrupted demand growth with trepidation. If the iron ore industry is any guide, though, small may still prove to be beautiful.

While steel production has continued to grow in recent years, the bit of it that matters to iron ore producers has mostly stagnated. Global output of pig iron — the hot metal that comes out of blast furnaces — grew at an average 6.2% a year in the decade through 2012. In the subsequent five years, that pace slowed to 1.1%.

That ought to have been bad news for the people digging rust out of the ground — and, indeed, in 2015 they had a brush with death due to signs that Chinese steel demand was drying up altogether. Once that storm settled and demand regained a measure of equilibrium, though, BHP Group, Rio Tinto Group, Vale SA and Fortescue Metals Group Ltd. found business rather profitable.

What happened? The best argument is that the bull case for iron ore went from a demand-led to a supply-led story. A short spike of extreme demand — like the one we saw last year, driving ore prices to a multi-year high of $176 a metric ton — provides a nice sugar boost. When demand growth is both strong and sustained, though, margins suffer, as miners spend all their cashflow on an orgy of capital expansions to provide the extra raw materials that consumers are crying out for.

Put that way, the end of demand growth isn’t all bad. The machinery built and deposits developed at the peak of the market should be able to keep chugging along, without adding too much more, reducing capex budgets. So long as producers are able to restrain supply, prices should hover around profitable levels. Once you’ve dealt with the debt hangover from boom times, business starts looking a lot more sane and sensible than it was in the glory days.

That’s the best case for what could be happening in the oil market right now. For all the apparent strength of crude demand growth out of China, there’s still very little sign that transport consumption is going to resume its upward trend, as my colleague Julian Lee has written.

China’s apparent gasoline demand has gone sideways for five years, with most of the growth in refinery output soaked up by exports. Covid-19 shows little sign of reversing that. Indeed, looking down the list of China’s major refinery products, it’s hard to see any that have seen a sustained improvement in consumption over the past year, with the exception of a minor bump in kerosene that matched the brief recovery in the country’s aviation industry.

That suggests growth is being driven by less-noticed fractions used as feedstock for China’s fleet of new petrochemicals plants — ultimately representing a shift in the location of the global chemicals and refining industry, rather than an increase in ultimate end-user demand.

As we’ve argued, the prospect of a plateau or decline in crude demand may not initially be as bad for oil producers as feared. Saudi Arabia, for instance, may see healthier oil revenues from throttling back output than opening the spigots.

That’s one possible explanation for its current willingness to shoulder the burden of supply restraint within OPEC+ on its own. Even Exxon Mobil Corp., the industry’s most perennial demand bull, seems to be capitulating to peak-ism, judging by its own spending plans.

Maintaining that happy equilibrium depends on accepting that the world has changed. Iron miners have shown impressive conformity in refusing to ramp up capital spending to previous levels in spite of their healthier profits in recent years — helping in the process to keep supply tight and prices elevated.

Oil producers are a much larger and more disorderly bunch, one reason the likes of OPEC+ exist in the first place. The biggest players will have to work harder than ever to enforce the sort of supply restraint that the miners have exhibited. If Big Oil wants to make the most money out of petroleum’s twilight years, the first step is accepting that the oil era is really coming to an end.

Updated: 2-6-2021

Big Oil Gets To Teach Climate Science In American Classrooms

Fossil fuel companies are spending big money to make sure their message reaches kids. Science teachers are doing their best to make sure they learn the facts.

If you were an elementary school student in Oklahoma, you might meet Petro Pete, a cartoon child outfitted in the overalls and hard hat of an oil rig worker. Through Pete, you might learn things like “having no petroleum is like a nightmare!”

Meanwhile Pete’s trusty blue dog, Repete, assures the animal kingdom that “the humans learned their lesson and now they don’t leave behind a mess when they drill for oil.” Who would you have to thank for these important academic messages? Oklahoma Oil & Natural Gas, a fossil fuel industry trade group.

In Ohio, children may complete a word search sponsored by the state’s oil and gas industry, with answers such as “lubricants” and “carbon black,” while in New Jersey students in grades three through six may receive a workbook titled “Natural Gas: Your Invisible Friend.”

The National Energy Education Development Project, backed by 100 oil and gas industry players, promotes lessons on fracking using Jell-O and other fun foods as teaching aids.

The stakes for how children and young adults learn about climate change—the science, the politics, the implications—are extremely high. Environmentalists know this.

So, clearly, do fossil fuel companies. “Industry groups recognized the value of classrooms for marketing and propaganda decades ago,” says Carroll Muffett, president and chief executive of the Center for International Environmental Law.

“It’s where you shape someone’s understanding of your product and of your company and of your issues. In a school context, you’re shaping their understanding of the world.”

One of the many ironies of K-12 education on climate change is that among the parents, at least, there’s little discord. More than 80% of parents said that they want schools to teach their children about climate change, according to a 2019 NPR/Ipsos poll.

That survey also found that whether people have children or not, nine out of 10 Democrats and two-thirds of Republicans agree that the subject needs to be taught in schools.

Yet the forces trying to suppress accurate science teachings remain relentless, says Elizabeth Allan, president of the National Science Teaching Association. Allan teaches climate change to many students in Oklahoma whose parents work in the oil industry, and they come to class with preconceived ideas about what climate change is and isn’t.

“When I’m talking to them, it doesn’t lessen the science,” she says, “or the need for them to understand or examine fossil fuels and human contributions to it.”

Allan’s organization, which has 40,000 members, is the largest science teaching membership organization in the U.S. Its website offers sample lessons and guidance for constructing scientifically-sound climate change curriculum to try and rebut the fossil fuel interests. “The younger you are” when you first encounter climate change, she says, “the more aware you are that climate science is real and that there are real consequences for the future.”

Ben Abbott, a science teacher in Orem, Utah, says that he’s often approached by teenagers and adults asking him questions about science-related things ranging from how the atmosphere works to how light waves reflect, but most often, they’re about climate.

Even when his questioners are 18 and younger, they’re often already intensely curious and concerned. Abbott knows better than to try to argue the facts. “Most people believe what they believe not because they have considered other options, but because of the people around them that they trust, people in their community have told them,” he says. “That changes the dynamic.

You no longer think, ‘Oh, these people are dumb.’” The cycle of influence flows both ways, though. Evidence exists that children—who may be heavily influenced by their parents’ political ideologies but are also less entrenched in a single set of beliefs—can change their parents’ minds about climate change.

Aside from the corporate influence on curriculum, much of how climate change is taught varies by state, leading to a patchwork of outcomes. At least 10 states, including Texas, offer teachers little to no guidance on the topic of climate change. No states currently prohibit lessons on man-made environmental issues, while in June of last year, New Jersey became the first state in the country to require climate change education in its public schools.

The new rule “goes that extra step,” says Guida Faria, a K-12 science supervisor for Fanwood School District in Scotch Plains, N.J., and president of the New Jersey Science Teachers Association. “Before, the standards said that you should look at how humans impact the Earth and now climate change is explicitly put there,” Faria says. Now teachers don’t have a choice.

The guidelines, which will impact more than 1.4 million students, cover seven different subjects, including physical education, social studies, and the visual and performing arts.

On the one hand, some teachers might be wary of addressing what is still, after decades of misinformation on the subject, a controversial issue. On the other hand, says Faria, the policy gives teachers cover should they face any public blowback.

The question is how to teach them—and often, how much to scare them. The American Academy of Pediatrics’ policy position on children and climate change notes that “the social foundations of children’s mental and physical health are threatened by the specter of far-reaching effects of unchecked climate change, including community and global instability, mass migrations, and increased conflict.”

“I frame it as, ‘Humans are in charge.’”

There’s a valid case that children should be terrified of the multi-generational failure of adults to rein in the problem they created and political leadership in Washington that still regards climate change as little more than a hoax. But young people don’t see it as an abstract threat.

When the Washington Post and the Kaiser Family Foundation polled U.S. teenagers in the summer of 2019 on their feelings toward climate change, 57% said it made them feel “afraid,” while 43% said it made them feel helpless. Those feelings can be especially difficult for younger kids to deal with.

One episode of the HBO drama Big Little Lies revolves around a grade school-aged girl who has a panic attack during a classroom discussion of sustainability, folded into a lesson about Charlotte’s Web.

When the students (and adults) Abbott encounters express doubt that climate change is real, he tries to start with simple physical science ideas where there’s common ground—how the scientific method works, the properties of water, what plants need to live—and work his way outward, one lesson at a time.

“The temptation is to do a data blast,” says Abbott, who has a PhD in ecosystems ecology. “To say, ‘I know stuff.’ It’s really easy. But if you’re persuading or connecting, you have to start toward that place of cultivating compassion. The goal is for students to leave with a feeling of urgency and empowerment.”

The good news, Abbott says, is that because climate change is man-made, it stands to reason we just might be able to unmake if we act quickly. “I frame it as, ‘Humans are in charge.’”

As some educators lean into the macro lessons, others localize. Timothy Gay, a high school science teacher in Boston, tells his students to look at the implications of climate change along the New England coastline, ranging from flood risks to mass unemployment in the lobster industry should the deterioration of the world’s oceans continue.

Once kids are old enough to handle it, a little fear into them can be motivating—especially given the recent resurgence in youth activism around the world. “When I first started teaching [15 years ago], it was all doom and gloom,” Gay says. “But there’s been a shift in the student psyche. They want to solve the problem. It’s a big issue on the planet, we have the science but now they want to figure out local solutions.”

The truth of climate change is laid especially bare in the classroom of Nancy Metzger-Carter, who teaches in Sonoma County, Calif. She’s taught climate change for 14 years, she says, but “the way I teach now is totally different.” Several of her students were displaced by the wildfires that burned through more than 4 million acres in the state last year.

Yes, lessons in turning out the lights when you leave the room, calculating carbon footprints, and choosing electric cars come up. “But to me, those solutions always felt like they were not enough,” she says. “It’s an equity issue. I can’t tell a kid who can’t afford school lunch to become a vegetarian.

It really ignited in me that wow, this is a huge, systemic problem that’s happening that requires systemic solutions.”

It’s not uncommon for science teachers themselves to be confused about the facts. A survey of teachers published in Science in 2016 found that many of them, intentionally or not, are passing along that incomplete understanding to their students. Nearly one in three incorrectly taught that global warming is not man-made.

Metzger-Carter herself has engaged in activism on the federal level. Along with a group of her high schoolers, she helped draft House Resolution 574, “Supporting the teaching of climate change in schools,” introduced by Rep. Barbara Lee, a Democrat from the California district encompassing Oakland and Berkeley.

“We want to empower students and really call out what needs to happen, which is a massive, systemic policy change,” Metzger-Carter says.

Her co-writers included Ella Crenshaw, 17, and Blue Stringer, 17, who set up virtual meetings with lawmakers in Washington to share their first-person stories about climate change and advocate for more green-friendly legislation.

When the fires in September turned the skies outside their windows Mars orange, they were scared, they say, but they were also prepared—and that made them really, really angry.

Having lived through a previous series of devastating wildfires four years ago, Crenshaw says she automatically began to think of what possessions she should pack if she and her family had to evacuate.

“I thought, ‘Is there a fire coming down the hill like in 2017?’” Crenshaw says. She and her family turned out not to be in danger, but signing into Zoom school “felt almost disrespectful—the whole day felt weird,” she says.

Because of their climate change lessons in school, there was no ambiguity in her understanding of what was transpiring. “With climate change, this is only going to multiply,” Crenshaw says

Stringer chimes in. “Climate change is such an intense, global issue,” she says. “You can’t ignore that fact. You can’t escape the fires here and there are so many different times where the issue is constantly being brought back to us.”

“I think our generation really acknowledges this is falling on our shoulders,” Crenshaw adds. “It’s up to us.”

Updated: 2-7-2021

Oil Futures Settle Higher, With U.S. Prices Up 9% For The Week

Brent Crude Logs Highest Finish Since January 2020

Oil futures settled higher on Friday, with Brent crude nearing the $60-a-barrel threshold and U.S. benchmark prices up roughly 9% for the week, boosted in part by expectations for stronger energy demand and production restraint by major oil producers.

“Besides ‘soft’ factors such as increased demand from investors in view of the pronounced price buoyancy, rising stock markets and economic optimism, the physical market is also looking increasingly tight,” said Eugen Weinberg, commodity analyst at Commerzbank, in a note.

West Texas Intermediate crude for March delivery CL.1, 0.88% CLH21, 0.88% rose 62 cents, or 1.1%, to settle at $56.85 a barrel on the New York Mercantile Exchange, leaving front-month U.S. benchmark prices up 8.9% for the week, according to Dow Jones Market Data. Prices marked their highest finish since Jan. 21, 2020.

April Brent crude BRN00, 0.83% BRNJ21, 0.83%, the global benchmark, advanced 50 cents, or nearly 0.9%, to $59.34 a barrel on ICE Futures Europe, up 7.8% for the week to settle at their highest since Jan. 29, 2020. Prices, based on the front-month contract, scored a sixth straight session gain, the longest streak of climbs since the seven-session rise ended June 5, 2020.

Brent is testing the key $60 level and if successful, “it would mark the first time crude prices have traded above that level since COVID-19 first started to significantly impact prices,” said Robbie Fraser, manager of global research and analytics at Schneider Electric, in a note.

“The move speaks to the ongoing strength of a broader rally that has carried over from late 2020, largely pushed forward by broader market optimism and the start of successful vaccine deployment around the world,” he said. “While near-term headwinds have emerged, the longer-term optimism remains intact, bringing steady support.”

In an indication of robust demand, Weinberg noted that despite higher prices, Saudi Arabia won’t be granting discounts to Asian customers in March, and will leave price premiums in place despite expectations for a cut.

The analyst, however, argued that optimism over demand, which is shared by major oil producers, who look for demand to return to record 2019 levels as early next year, is overdone.

“We see such forecasts as ambitious and expect prices to correct in the coming months,” Weinberg wrote.

For now, oil prices remained underpinned by expectations that the Organization of the Petroleum Exporting Countries and its allies, together known as OPEC+, will continue keeping a lid on output, as the global economy makes headway toward a recovery from the COVID-19 pandemic.

OPEC+ made no changes to output curbs at a monthly ministerial committee meeting Wednesday, and in a statement said its “optimistic for a year of recovery” in 2021.

Saudi Arabia agreed to unilaterally cut one million barrels per day from its output this month and next, but James Williams, energy economist at WTRG Economics, warned that the country can “just as easily return it to the market.”

If Brent prices hit $60, he told MarketWatch he believes the Saudis would try to talk down the price.

“The big reason to keep Brent below $60 is that at $60 Brent WTI is well over $55 per barrel making almost all U.S. shale profitable,” Williams said. “At $55 you get enough increase in U.S. drilling and completions to reverse the downward trend in production. If WTI stays at $55, within six months the U.S. will be putting more crude on the market.”

Over in the U.S., Baker Hughes BKR, -1.25% reported Friday that the number of active U.S. rigs drilling for oil rose for an 11th week in a row, pointing to a potential increase in production.

Back on Nymex, March gasoline RBH21, 0.72% tacked on 0.3% to $1.6493 a gallon, ending 6.2% higher for the week. March heating oil HOH21, 0.67% rose 0.8% to $1.7137 a gallon, for a 7.2% weekly rise.

Natural-gas futures briefly topped $3 per million British thermal units on Friday before settling lower. It hasn’t ended a session above $3 since November.

March natural gas NGH21, 1.50% edged down by 7 cents, or nearly 2.5%, to $2.863 after trading as high as $3.057. For the week, prices rose by nearly 12%.

“Prices have rallied this week on the back of weather forecasts showing extremely cold temperatures across large portions of the U.S. throughout most of February, which is expected to strongly boost heating demand for gas, and swiftly draw down on storage levels,” said Christin Redmond, commodity analyst at Schneider Electric.

Data from the Energy Information Administration Thursday revealed a 192 billion-cubic-foot decline in weekly U.S. natural-gas supplies, which was 46 Bcf larger than the five-year average withdrawal for the same week, according to Redmond. “As a result, the storage surplus decreased to 7.9%.”

Updated: 2-17-2021

Oil Prices Are Up, But Frackers Stay On The Sidelines—For Now

Some producers are unable to benefit from the rally as they work to restore output in Texas and other regions hit hard by winter storms.

Oil’s recent rise above $60 a barrel will test the willpower of shale companies that pledged to slow drilling and repair balance sheets battered by the pandemic.

The highest prices since January 2020 have given U.S. drillers an unexpected opening to invest in oil patches considered unworkable just a few months ago. Some, such as Devon Energy Corp. DVN 3.80% , have begun to loosen the purse strings as the market improves.

For now, though, many frackers are unable to take advantage of the rally as they work to restore as much as roughly one-third of the nation’s oil production. The winter storm that left millions without power this week knocked out as much as 2.5 million barrels a day in the Permian Basin and Eagle Ford of Texas and one million in other oil-rich states, traders estimated.

Icy roads have blocked service crews from reaching wells, and analysts estimated the disruptions could affect production through March. It will take weeks to determine exactly how many barrels will have been lost to the storm, Devon Chief Executive Richard Muncrief said.

In earnings calls this week, shale executives said they are sticking to capital discipline, which has become a mantra of the industry following a yearslong push by investors.

Some said they plan to restrain growth this year in spending, drilling and production, anticipating they will reinvest roughly 70% of their cash flows from operations back into drilling, with the rest paying for debt and shareholder dividends. For years, U.S. shale companies had run up debts by spending more on capital projects than they made from actually selling oil and gas.

Devon also said it would pay a variable dividend of 19 cents a share, or about $128 million, at the end of the first quarter. The dividend fluctuates depending on levels of available cash.

In an interview, Mr. Muncrief said higher oil prices sustained at $60 a barrel would only raise the amount of money the company returns to shareholders.

“That’s what it’s going to take for the world to stabilize,” Mr. Muncrief said. “It will take more discipline for U.S. producers to give the market confidence.”

Still, Devon and others have started to lift spending from last year’s low levels and venture into new regions. Devon, which acquired rival WPX Energy Inc. last month, said its capital spending could reach up to $1.8 billion this year, about 56% higher than Devon alone spent in 2020 and close to the $1.9 billion it invested in 2019.

Continental Resources Inc., CLR 4.11% the largest producer in North Dakota’s Bakken Shale, said it plans to purchase thousands of acres in Wyoming’s Powder River Basin for $215 million and raised its capital budget to $1.4 billion, up 21% from last year. It expects to generate $1 billion in free cash flow this year.

ConocoPhillips, the largest independent U.S. oil producer, said it is planning to spend roughly $5.5 billion on capital projects, about 17% more than it did in 2020. Still, if oil prices stay relatively high, the company expects its dividend alone won’t be enough to meet its goal of returning more than 30% of its cash from operations to investors.

“You should not be surprised to see us reactivate buybacks as a channel, and we always like the idea of improving net debt,” CEO Ryan Lance said.

The shale industry’s planned investments are still below pre-pandemic levels. But if oil prices hold above the mid-$50-a-barrel range, the largest U.S. shale drillers could collect enough cash to reinvest an additional $6 billion in drilling, up more than one-quarter compared with plans set in November, according to the consulting firm Rystad Energy.

That increase would bring the total investment for those companies to about $28 billion.

“The bigger companies may fine-tune their spending plans, but I don’t see anyone going crazy,” said John Applegath, a former executive at U.S. driller Range Resources Corp., now working as a consultant. “Smaller, private-equity-backed companies may see this as a way to break free. Some of them could drill twice as many wells as they had planned.”

At the same time, the oil-production outages in Texas and other states have dealt a blow to drillers’ future revenue. The outages have been the largest disruption to U.S. supplies on record, Rystad said.

Continental, which also operates in Oklahoma, said it is currently producing about 50% of its gas while other operators have kept pumping 5% to 25% of their natural-gas volumes. Continental said it is working with pipelines and power companies to keep compression equipment and wells running.

“We’re getting pretty well stressed here with our electric grids, power systems,” Continental CEO William Berry told investors Wednesday. “We just need to put every bit of effort possible into making sure we load all the gas that we could.”

Updated: 2-21-2021

Shale Companies Re-Emerge At Slippery Time

Oil-and-gas producers coming out of bankruptcy could be tempted to grow aggressively again with today’s higher prices.

Shale companies’ debts have been forgiven. Will investors forget?

Former drilling giants are testing their footing in the public markets after a near record number of reorganizations in 2020. It was the second-largest year for oil-and-gas producer bankruptcies—measured by debt volume—since the law firm Haynes and Boone started tracking the numbers in 2015.

Chesapeake Energy, once the second-largest natural-gas producer in the U.S., started trading on the Nasdaq last week as a shell of its former self: Its market capitalization is roughly $4 billion, a little over a tenth of what it was at its peak.

Whiting Petroleum and Oasis Petroleum emerged from bankruptcy in late 2020, also at fractions of their heyday valuations. Their shares are up 59% and 65%, respectively, since they started trading after emerging from bankruptcy.

Their re-entry is well timed with oil prices back to pre-pandemic levels: U.S. benchmark oil prices are now more than $10 a barrel higher than what it costs an average U.S. producer to profitably drill a new well, and natural-gas prices are back above the $3 per million British thermal units mark, buoyed by cold weather.

Yet prime conditions can be a slippery slope for a boom-and-bust industry prone to drilling too much when prospects look up. The temptation is especially high when capital is easy to raise, as it is now with investors hungry for yield.

While not many energy companies have tested the waters with new equity issues, plenty of investors are interested in buying existing shares: A broad basket of exploration and production companies have fully recovered to pre-pandemic levels. Borrowing is easy, too. Demand is sky-high for riskier bonds, a bucket that many energy companies’ debt falls into.

There are natural buffers in place that could put a brake on drillers’ return to a growth mentality. Previously burned lenders wound up with equity in reorganized companies and have a say in appointing new board members.

Yet that mechanism alone isn’t enough, as companies that double-dipped illustrate. Ultra Petroleum and Chaparral Energy are among companies that filed twice for bankruptcy—once in 2016 and then again in 2020. Both have emerged from restructuring and have been taken private.

Is anything different this time around? One important change is more-conservative assumptions. When a wave of energy companies went bust in 2016, they shuffled their capital structures with the expectation that prices would bounce back quickly, as they did in the aftermath of the previous global recession, Patrick Hughes, partner at Haynes and Boone, points out. That left companies with heavier debt burdens than they could handle.

During the 2008 crash, West Texas Intermediate oil prices plunged below $40 a barrel but recovered to $60 in just six months. By 2011, prices crossed the $100 mark. But the situation was different eight years following the crash when the U.S. was producing 77% more oil using much cheaper methods.

As Dan Pickering, chief investment officer of Pickering Energy Partners, notes, “We learned that the U.S. can oversupply the market.” Prices plunged to $30 a barrel in 2016 and took two years to return $60. The double whammy of the Saudi-Russia price war and the global pandemic sent prices plummeting again last year.

For now, that experience might be enough to keep companies and investors from returning to a “drill, baby, drill” mentality. So is the prospect of major exporters loosening the spigots. Saudi Arabia already plans to increase oil output in coming months, as The Wall Street Journal has reported.

“We’ll have to see prices in the $50-$60 range for at least a year before a combination of companies and Wall Street are willing to think about growth again,” according to Mr. Pickering.

What hasn’t changed? Basic human psychology. When prospects look good, neither company executives nor their investors can resist growth. That is true of equity markets in general, but especially so in a depletion business like drilling, where no investment means no future returns.

In this choose-your-own-adventure story, chapter 11 remains a tough one to avoid.

Updated: 3-2-2021

Big Oil Is Unwilling To Bet On The Future Of Crude

The reserves-to-production ratio, which gauges long-term prospects across the industry, has fallen below critical levels.

For a century, there’s been a key metric for judging the direction of the oil industry: The number of years it would take for wells to run dry.

The reserves-to-production ratio or R/P — calculated as oil reserves, divided by annual production — has remained at eerily consistent levels since John D. Rockefeller’s day. At major oil companies and in the U.S. as a whole, it has rarely dropped below 10, and those moments have been associated with major disruptions.
Perfect 10

The U.S. has almost always kept enough oil reserves to continue production at current levels for a decade.

When America’s R/P slipped below the critical level in the late 1960s, it came amid fears that the country might be approaching peak oil, heralding the heady geopolitics of the 1970s oil crises.

When Royal Dutch Shell Plc’s R/P fell below 10 in 2004 due to a reserves writedown, the event was a major scandal, prompting the departure of a string of top executives and the payment of nearly half a billion dollars to aggrieved shareholders.

Now, Big Oil is running down its tank again. That’s an indication that when executives say oil demand may have peaked and the world is transitioning fast to renewables, it’s more than just words.

If you still think crude will see bright prospects in the 2030s, you should be exploring and developing the oilfields to supply it. As with the collapse in their non-maintenance capital expenditure since 2016, the erosion of petroleum reserves is a sign that even Big Oil is capitulating to the decline of its key product.

Take Exxon Mobil Corp., whose traditionally Texas-sized R/P hasn’t fallen below 13 years in data going back to 1993. The 15.2 billion barrels of reserves declared in its annual report last week would run out in 11.05 years at 2020’s production rates. At the average of the three previous, non-pandemic-hit years, it would run for just 10.62 years.

Chevron Corp.’s more modest reserve reduction announced the following day had the same effect, reducing its R/P to 9.89 — the first drop below 10 since at least 1998. Shell, meanwhile, has been running on fumes for some time.

At the end of 2020, it was holding onto just 7.34 years of production, and Chief Financial Officer Jessica Uhl has declared the measure more or less irrelevant for the future of the business. “The reserves will be what the reserves will be,” she told an investor call last month.

While official figures for BP Plc and Total SE won’t be clear until they publish their annual reports later this month, all the supermajors appear to be trending in the same direction. BP’s production chief Gordon Birrell, for instance, told investors last September the company would target an eight-year R/P ratio, without giving a date for it.

Things are little different at the non-OPEC state oil companies, which in the 2000s were seen by many as the future of crude production. Petroleo Brasileiro SA and India’s Oil & Natural Gas Corp. both now have R/Ps well below 10, while PetroChina Co. is heading rapidly down the same path.

On a national level, traditional major exporters such as Ecuador, Indonesia, Mexico, and Trinidad and Tobago, have all fallen below 10. If it wasn’t for the vast, multi-decade deposits in the Middle East and Russia — plus huge pools of heavy oil in Venezuela and Canada that may never be developed — the world would be looking distinctly short.

None of these numbers mean that oil production will stop when current reserves run out. The core business of resources companies is to constantly add to their reserves — one reason why U.S. crude supplies didn’t run out in the middle of World War II, as some of the earliest R/P ratios around the start of the 20th century would have suggested.

Reserves are also profoundly affected by expectations about where the oil price is headed. Technically, they’re the bit of an oil reservoir that companies expect to be able to produce profitably. That means a reduction in price estimates can push reserves into the red, causing petroleum to disappear with the stroke of an accountant’s pen, as my colleague Liam Denning has written.

That raises the prospect that the climbing prices in recent weeks could cause these numbers to jump back at some point — but there’s little sign of that in the performance of longer-run futures, which are still around the same $55 a barrel level they’ve been languishing at for several years.

What does the demise of the R/P ratio mean, in that case? It’s not so much the death of oil, as evidence that the industry is unwilling to bet on its survival. Investors no longer want to see capital wasted developing assets whose profitability will depend on the state of crude demand more than a decade hence — especially when the world is trying to shift that demand into terminal decline. 2

The petroleum era is in its twilight years. Big Oil doesn’t want to get caught out when it ends.

Updated: 3-7-2021

Saudi Arabia Plays Chicken With U.S. Shale

OPEC+ delays opening the taps until the post-Covid demand recovery is stronger, betting Permian Basin rivals won’t be tempted to “drill, baby, drill.”

“Drill, baby, drill is gone forever.” That’s the view expressed by Saudi energy minister Prince Abdulaziz Bin Salman after last week’s meeting of the alliance of oil producers known as OPEC+.

The prince, who enjoys surprising the oil market, was riding high. He had just encouraged and cajoled his colleagues into accepting, for another month, his careful approach to adding back the supply they took off the market last May. He urged caution from the get-go, offering the view that demand recovery will remain fragile until Covid vaccine campaigns are much further along.

Not only did the OPEC+ group as a whole agree to defer an easing of their production targets — Russia and Kazakhstan were granted small increases, apparently to meet a seasonal uptick in demand — Saudi Arabia also extended its additional voluntary cut for another month. It will now run to at least the end of April and then only be restored in stages.

The oil market had been expecting as much as 1.5 million barrels a day of production to be restored in April. It got just one tenth of that, and Brent crude promptly jumped toward $70 a barrel, a level not seen since May 2019.

What was striking is that Prince Abdulaziz is clearly concerned oil consumption may not evolve along the lines foreseen by OPEC’s own analysts. He would rather tighten the oil market than risk another collapse. And even with oil prices back at pre-pandemic levels he’s still confident they won’t spur a third shale boom.

He may well be right.

As I argued here and here, the second shale boom was already coming to an end several months before the Covid-19 pandemic struck and producers capitulated in the face of the price collapse that followed hard on the heels of the virus.

Oil production from seven major shale regions tumbled by 2.4 million barrels a day, or more than a quarter, in the six months from November 2019 to May 2020. Oil prices only began to fall in January 2020, with the slide not gathering momentum until March, so the slump in production wasn’t initiated by lower prices.

Going into the meeting, it wasn’t clear the Saudi prince could convince his fellow OPEC+ oil ministers that the threat of a resurgent shale sector has vanished. His Russian counterpart Alexander Novak warned back in December that a “price range of $45 to $55 a barrel is the most optimal,” for the group to start opening its taps. “Otherwise we’ll never restore production, others will restore it.”

The Saudis are willing to gamble that Novak’s wrong, even with oil prices at $65 to $75 a barrel and likely to move higher.

Drilling activity and well completions in seven major shale regions have picked up a little from their low points of last summer, but aren’t yet back even to the lows experienced between the first and second shale booms (see chart above). Companies operating in the shale patch have been forced by investors and lenders alike to pull back from their earlier growth-at-all-cost strategies to ones that return profits to shareholders and pay down debt.

Shale companies “have had their fair share of adventure and now they are listening to the call of their shareholders,” Prince Abdulaziz told my Bloomberg News colleagues after Thursday’s meeting.

Companies from Exxon Mobil Corp. on down have been scaling back production plans for their shale assets. The U.S. major has cut its 2025 output target for its Permian Basin operations by 30% to 700,000 barrels a day and slashed the number of rigs it is using there to 10, down from 55 before the pandemic.

But the higher prices go, and the longer they stay there, the more likely it is that calculation could change. Especially given that shale producers may now be in a position to lock in prices for future output that are high enough both to generate profit and increase production. Brent crude is already trading above $60 a barrel all the way out to the end of next year, giving companies plenty of scope to hedge production at a profit.

Prince Abdulaziz is hoping that by the time they get the bits turning and new wells pumping, the demand recovery will be secure enough for him and his allies to open their own taps. In the meantime, his only consolation for those customers, such as India, who want more of his oil was to tell them to draw down some of the stockpiles they built up so cheaply last year.

Updated: 3-11-2021

Oil Giant Shell Appoints New Chairman To Navigate Energy Transition

Former BHP CEO Andrew Mackenzie to help guide company’s plans to reduce reliance on fossil fuels and expand in low-carbon energy.

Royal Dutch Shell PLC has appointed Andrew Mackenzie as its new chairman, tapping a mining veteran to oversee the oil and gas giant as it navigates the transition to low-carbon energy.

The Anglo-Dutch company said Thursday that Mr. Mackenzie, who joined its board as a nonexecutive director in October, would succeed outgoing chairman Chad Holliday in May.

A Scottish-born geologist, Mr. Mackenzie is best known as the former chief executive of BHP Group Ltd., one of the world’s largest mining companies, which he ran for six years to 2019. During his tenure at BHP, he is credited with simplifying its business, overseeing the sale of its U.S. shale-gas assets and carving out several mining operations into a new company called South32 Ltd.

Before that, Mr. Mackenzie worked at rival miner Rio Tinto PLC, and previously spent 22 years at BP PLC, in areas including research and development, petrochemicals, and exploration and production.

Mr. Mackenzie’s appointment at Shell comes as many big oil companies are grappling with the transition away from fossil fuels toward lower-carbon energy like wind and solar power. Governments and companies are increasingly moving to reduce reliance on fossil fuels to curb carbon emissions, while growing technologies like electric vehicles are expected to dampen future demand for diesel and gasoline.

Last month Shell said it planned to reduce oil production, ending a decades-old strategy centered on boosting oil and gas output. Instead, the company said it would focus on growing the amount of electricity it sells and boosting its low-carbon energy activities such as electric-vehicle charging.

Mining, like oil and gas, has also faced scrutiny over emissions, particularly the pollution caused by customers using the commodities it produces. While at BHP, Mr. Mackenzie laid the foundations for medium-term decarbonization goals and pledged to invest millions of dollars to develop technologies to help customers reduce emissions.

The BHP role also gave Mr. Mackenzie experience in the running of a business that has sprawling global operations and exposure to sometimes volatile commodity markets.

Shell and its peers are also seeking to recover from one of their worst years on record after the pandemic decimated energy demand, sending oil prices lower. The company moved quickly to reduce costs, cutting thousands of jobs, and wrote down the value of its assets by billions of dollars.

Shell also cut its dividend for the first time since World War II, a move that Mr. Holliday—who departs after six years as chairman—described as the most difficult decision he had experienced on a company board. Shell would have needed to borrow money to sustain the payout otherwise, he wrote in the company’s annual report published Thursday.

Mr. Mackenzie said it was a “pivotal time for the industry and wider society” and that he looked forward to working to “accelerate Shell’s transition into a net-zero emissions energy business.”

Updated: 4-4-2021

Pioneer’s $6.4 Billion Deal For Smaller Shale Rival Signals Life In Oil Patch

The purchase of DoublePoint Energy is the largest for a privately held shale driller since 2011, underscoring recent momentum as oil tops $60 a barrel.

Pioneer Natural Resources Co. PXD 3.64% ’s $6.4 billion deal to buy DoublePoint Energy this week is the latest sign of renewed interest in smaller shale drillers as oil prices recover from last year’s pandemic lows.

The deal, announced Thursday evening, was the largest acquisition of a privately held shale company since 2011. It follows the sale of a number of smaller oil-and-gas companies and demonstrates momentum in what had been a moribund market, according to executives, investors and data from consulting firm Enverus.

The market for private oil-production firms had collapsed in recent years as investors, frustrated following years of dismal returns, pushed larger shale companies to curtail investments and stop buying smaller debt-laden companies.

That has changed in recent months—at least for the private companies with better assets and lower debt—as U.S. benchmark prices hover above $60 a barrel. A surge in the shares of U.S. oil producers, following the rollout of Covid-19 vaccines and a slow but steady recovery in oil demand, is enabling larger companies to use their equity to pay for targeted acquisitions.

Pioneer, led by Chief Executive Scott Sheffield, plans to issue 27.2 million shares and spend $1 billion in cash in the DoublePoint deal, set to close in the second quarter. It will assume about $900 million of the smaller company’s debt and liabilities.

The transaction comes a few months after Pioneer bought Austin, Texas-based Parsley Energy Inc., a company co-founded by Mr. Sheffield’s son, Bryan, in a deal valued at $4.5 billion.

Pioneer President Richard Dealy said rising oil prices have helped many companies improve their balance sheets more quickly than anticipated, making smaller companies more attractive targets. Still, smaller companies will have to conform to the U.S. oil industry’s new doctrine of curtailing spending and production growth if they want to get bought, he said.

Pioneer plans to dial down DoublePoint’s growth projections from an anticipated 30% a year to the 5% range, “consistent with our game plan,” Mr. Dealy said.

Pioneer’s market value has surged to $35.6 billion, from $13.9 billion six months earlier on Oct. 1. In that same period, the collective market capitalization of the 25 largest U.S. oil-and-gas producers has climbed about 89% to $769 billion, according to data from S&P Global Market Intelligence.

As oil and shale company share prices have climbed, so have deal valuations. Pioneer’s deal values DoublePoint’s land at north of $30,000 an acre, according to Enverus, up from an average of $10,000 an acre across sales last year in the Permian Basin of West Texas and New Mexico. Pioneer said it estimates the price tag valued DoublePoint’s acreage in the low $20,000-an-acre range.

Wil VanLoh, chief executive of Quantum Energy Partners, one of DoublePoint’s backers, said DoublePoint had engaged with several interested buyers on the lookout for smaller companies with low debt and prolific acreage.

“There’s only a handful of qualified companies. They’re going to be selective,” Mr. VanLoh said of buyers. Still, he added, Pioneer’s “big competitors are going to say, ‘We need to hop on it before they digest it and they’re ready to go again.’ ”

Since December, four private-equity-backed U.S. oil companies have sold themselves in deals valued at a combined $1.6 billion, the first such deals since January 2020, Enverus data showed. That includes Diamondback Energy Inc.’s $862 million purchase of Guidon Operating LLC, a private driller in the Permian Basin.

DoublePoint has roughly 100,000 net acres, much of it near Pioneer’s land in the Midland Basin, which is in the largest U.S. oil field, the Permian.

Shawn Reynolds, portfolio manager at investment firm VanEck Associates, said he was initially taken aback by the price Pioneer agreed to pay for DoublePoint. But considering how close its acreage is to Pioneer’s, the deal made sense, he said.

“The more we can bring some of these larger private players into public discipline, that’s very good,” Mr. Reynolds said.

Updated: 4-19-2021

Historic Oil Glut Amassed During The Pandemic Has Almost Gone

The unprecedented oil inventory glut that amassed during the coronavirus pandemic is almost gone, underpinning a price recovery that’s rescuing producers but vexing consumers.

Barely a fifth of the surplus that flooded into the storage tanks of developed economies when oil demand crashed last year remained as of February, according to the International Energy Agency. Since then, the lingering remnants have been whittled away as supplies hoarded at sea plunge and a key depot in South Africa is depleted.

The re-balancing comes as OPEC and its allies keep vast swathes of production off-line and a tentative economic recovery rekindles global fuel demand. It’s propping international crude prices near $67 a barrel, a boon for producers yet an increasing concern for motorists and governments wary of inflation.

“Commercial oil inventories across the OECD are already back down to their five-year average,” said Ed Morse, head of commodities research at Citigroup Inc. “What’s left of the surplus is almost entirely concentrated in China, which has been building a permanent petroleum reserve.”

The process isn’t quite complete. A considerable overhang appears to remain off the coast of China’s Shandong province, though this may have accumulated to feed new refineries, according to consultants IHS Markit Ltd.

Working off the remainder of the global excess may take some more time, as OPEC+ is reviving some halted supplies and new virus outbreaks in India and Brazil threaten demand.

Still, the end of the glut at least appears to be in sight.

Oil inventories in developed economies stood just 57 million barrels above their 2015-2019 average as of February, down from a peak of 249 million in July, the IEA estimates.

It’s a stark turnaround from a year ago, when lockdowns crushed world fuel demand by 20% and trading giant Gunvor Group Ltd. fretted that storage space for oil would soon run out.

Stockpile Slump

In the U.S., the inventory pile-up has effectively cleared already.

Total stockpiles of crude and products subsided in late February to 1.28 billion barrels — a level seen before coronavirus erupted — and continue to hover there, according to the Energy Information Administration. Last week, stockpiles in the East Coast fell to their lowest in at least 30 years.

“We’re starting to see refinery runs pick up in the U.S., which will be good for potential crude stock draws,” said Mercedes McKay, a senior analyst at consultants FGE.

There have also been declines inside the nation’s Strategic Petroleum Reserve, the warren of salt caverns used to store oil for emergency use. Traders and oil companies were allowed to temporarily park oversupply there by former President Trump, and in recent months have quietly removed about 21 million barrels from the location, according to people familiar with the matter.

The oil surplus that gathered on the world’s seas is also diminishing. Ships were turned into makeshift floating depots when onshore facilities grew scarce last year, but the volumes have plunged, according to IHS Markit Ltd.

They’ve tumbled about by 27% in the past two weeks to 50.7 million barrels, the lowest in a year, IHS analysts Yen Ling Song and Fotios Katsoulas estimate.

A particularly vivid symbol is the draining of crude storage tanks at the logistically-critical Saldanha Bay hub on the west coast of South Africa. It’s a popular location for traders, allowing them the flexibility to quickly send cargoes to different geographical markets.

Inventories at the terminal are set to fall to 24.5 million barrels, the lowest in a year, according to ship tracking data monitored by Bloomberg.

For the 23-nation OPEC+ coalition led by Saudi Arabia and Russia, the decline is a vindication of the bold strategy they adopted a year ago. The alliance slashed output by 10 million barrels a day last April — roughly 10% of global supplies — and is now in the process of carefully restoring some of the halted barrels.

The Organization of Petroleum Exporting Countries has consistently said its key objective is to normalize swollen inventories, though it’s unclear whether the cartel will open the taps once that’s achieved. In the past, the lure of high prices has prompted the group to keep production tight even after reaching its stockpile target.

Mixed Blessing

To consuming nations the great de-stocking is less of a blessing. Drivers in California are already reckoning with paying almost $4 for a gallon of gasoline, data from the AAA auto club shows. India, a major importer, has complained about the financial pain of resurgent prices.

For better or worse, the re-balancing should continue. As demand picks up further, global inventories will decline at a rate of 2.2 million barrels a day in the second half, propelling Brent crude to $74 a barrel or even higher, Citigroup predicts.

“Gasoline sales are ripping in the U.S.,” said Morse. “Demand across all products will hit record levels in the third quarter, pushed up by demand for transport fuels and petrochemical feed-stocks.”

Men Who Once Staked Claims For Oil And Gas Now Hunt For Wind And Sun

The slumping petroleum industry is shifting work from securing drilling rights to lining up properties for wind turbines and solar panels. But the landman profession is shrinking.

Carter Collum used to spend mornings shoulder to shoulder with competitors in the record rooms of East Texas courthouses, hunting for the owners of underground natural-gas deposits. At night, he made house calls, offering payments and royalties for permission to drill.

Mr. Collum worked as a landman, tracking the owners of oil and gas trapped in rock layers thousands of feet beneath the earth’s surface and getting their signatures, a job about as old as the American petroleum industry.

He started around 2006, a couple of years before the shale boom took off and pushed prices for drilling rights in East Texas to more than $15,000 an acre from around $250. Successful landmen, racing to knock on doors ahead of rivals, earned six-figure incomes.

“It was kind of like the Wild, Wild West,” said Mr. Collum, 39 years old. His predecessors in the field included former President George W. Bush and Aubrey McClendon, the late fracking pioneer who co-founded Chesapeake Energy Corp.

These days, the jobs are going dry. Landmen, after riding the highs of the boom, face weakened demand for fossil fuels and investor indifference to shale companies after years of poor returns. Instead of oil and gas fields, some landmen are securing wind and solar fields, spots where the sun shines brightest and the wind blows hardest.

The difference is shale wells eventually empty and, in good times, that keeps landmen on the prowl for new land and new contracts. Wind and solar energy never run out, limiting demand for new leases as well as landmen.

Renewable energy jobs are growing in the U.S., but last year roughly three-quarters of them were construction-related, according to consulting firm Wood Mackenzie. Even after last year’s oil-field job losses, U.S. oil and gas production employment is likely to outnumber renewable energy jobs for roughly another decade, according to the firm’s analysis.

Tami Hughes, one of the relatively few female landmen, contracts for an international oil company divesting U.S. assets. In 2019, there were more than 100 landmen and support staff on the divestment project, she said. Now, there are eight.

“If this job ends, I probably wouldn’t be able to get anything else until the price of oil and gas rises,” Ms. Hughes, 62, said.

Mr. Collum remembers the good times, when shale companies couldn’t find new deposits fast enough. They employed small armies of landmen who tracked down nieces, nephews and grandchildren who owned the rights to underground minerals, sometimes unbeknown to owners of the land above.

Mr. Collum had his own epiphany around 2006 while working as an assistant pro at the Peach Tree Golf Club in East Texas during a tournament for a group of high-spirited landmen. At his parents’ house the next night, Mr. Collum asked his dad what landmen did.

“Anybody that could breathe basically at that point could be a landman,” Mr. Collum said. Weeks later, he joined the ranks.

He spent some of his early years working the Haynesville, a natural gas field that stretches from East Texas to northwest Louisiana. As a contract landman for El Paso Corp., Mr. Collum would get assigned a region to lease and a rough budget.

Typically, he started by identifying either the largest tract of land in that area or the easy pickings, a family he already knew, for instance. He conducted title searches with a courthouse computer and record books, tracing who had bought, sold or inherited those mineral rights over the years.

Often, dozens of landmen were in the records room doing the same thing. If you got up from your seat to, say, pull another worn index book from the shelf, you left your yellow legal pad face down to prevent the next guy from rubbernecking, Mr. Collum said.

Then he chased leads. Negotiations were often done at a family’s kitchen table. Owners of oil or gas mineral rights typically get an upfront payment plus a percentage of the revenue. Mr. Collum focused his pitch on the likelihood his company would drill wells that would deliver royalties and financial security. “I tried to sell the future,” he said.

Dry Spell

Starting around 2015, landman work began declining in an oil-price plunge that forced many shale companies to cut back.

Work slowed further when Covid-19 swept the world, weakening oil demand and again forcing companies to retrench.

The U.S. oil-and-gas industry has been one of the hardest hit in the pandemic, shedding nearly 75,000 jobs last year, or roughly 19% of positions, according to Bureau of Labor Statistics data on oil-and-gas extraction and associated services.

Jobs involving evaluating and securing new drilling locations, such as landmen and geologists, were among the first cut when companies scaled back.

“There’s not much hope in it, really,” said Garet Edwards, a 37-year-old landman based in Oklahoma. “Oil and gas seems to be a never-ending battle.”

Mr. Edwards belonged to a generation of Oklahoma State University graduates who jumped into the shale land rush. He recalled the day he drove more than seven hours from Oklahoma to New Mexico to persuade a retired preacher to sign.

The deal allowed Devon Energy Corp. to edge out Chesapeake for control of a prized drilling area. Last June, Chesapeake, once the second-largest U.S. natural gas producer, filed for bankruptcy protection. Devon agreed last fall to join forces with WPX Energy Inc., a shale-patch union engineered to weather the pandemic price rout.

He, too, thinks back to the boom days. “You didn’t let the grass grow under your feet too long,” Mr. Edwards said. Now, he said, “You can step into any of these little old courthouses, and you might be the only one that’s been there all week.”

For two years, he contracted for a renewable-energy developer, signing up landowners to host wind turbines and solar panels. In 2018, he switched sides to represent landowners in renewable and fossil-fuel energy deals. Even that has slowed. He is considering part-time work selling insurance to ranchers.

Employment data for landman jobs isn’t broken out by the Labor Department. Membership in the American Association of Professional Landmen tumbled around 20% last year. The organization recently expanded its definition of landman work to cover renewable energy.

“For folks that even know what a landman is, you immediately think oil and gas. And over time, that’s not what you’re going to think,” said Lester Zitkus, president of the landman association and a Gulfport Energy Corp. executive.

Lee Grubb, an Oklahoma-based landman, said he had around 10 friends working as landmen in 2014, when federal data showed U.S. oil and gas employment at its highest level in recent decades. Only two remain, including Mr. Edwards. The other works for a renewable energy company.

“It’s kind of a shocker,” said Mr. Grubb, 39. “It was one of the hottest oil and gas areas in the world for a while, and there’s nothing going on out here now.”

Mr. Grubb travels the Southwest persuading ranchers to sign over land for wind and solar farms for Enel Green Power, a unit of the Italian utility Enel SpA. He earns more on average in renewables than he did in oil and gas, where he could go a year or two with little or no land work when prices were low, he said.

He also travels more, clocking around 60,000 miles a year making house calls. Many of the people he visits are more familiar with oil and gas than wind or solar power. Part of his job is educational. Wind and solar leases generally offer less money up front but steadier payments that could stretch for decades, he said.

“You’re trying to get everyone’s minds wrapped around that,” Mr. Grubb said.

Rick DePriest didn’t need much convincing before he and his wife signed up about a decade ago for wind turbines to be built on their roughly 450-acre property southwest of Oklahoma City. Together, the two turbines bring them about $20,000 a year, money the DePriests plan to use to supplement their retirement. “Low-impact income,” Mr. DePriest said.

Energy Exploration

Jim Stout, a landman based in the Pittsburgh area, was laid off in late 2019 from EQT Corp. , the largest U.S. natural gas producer. Mr. Stout, 42, spent more than a year piecing together jobs that included selling real estate and building storage facilities. His income, he said, fell by about half.

“The idea is don’t ever rely on being in one job again,” Mr. Stout said.

This month, he started as a full-time contract landman, helping identify and secure land for solar farms. Opportunities for higher pay in fossil fuels make returning one day to the industry attractive, he said, but “it’s hard to see when the next boom phase in oil and gas might be.”

U.S. benchmark oil prices have rebounded to around $60 a barrel from a pandemic low of negative $37.63 last April, spurring companies to deploy additional drilling rigs and resume some hiring.

Yet employment in U.S. oil and gas production has likely peaked, according to Wood Mackenzie. The firm expects industry jobs to increase some 18% from 2021 through 2027, to around 424,000 positions, before slowly declining as technology improves.

Renewable energy and related fields are forecast to attract roughly 60% of the world’s energy investment from 2020 through 2030, according to the International Energy Agency, up from around 48% from 2015 through 2019.

When shale driller Marathon Oil Corp. laid off Mr. Collum last spring, he figured another oil-and-gas job would be hard to come by. He began taking online real estate classes, but he found a landman job at a small firm in his hometown of Tyler, Texas.

The company, Vernon E. Faulconer Inc., operates existing wells rather than drilling new ones, and Mr. Collum works mostly from his desk. He was recently scouting for properties to dispose of wastewater that is produced along with natural gas.

He worries about finishing his career as a landman. “Man, I’ve got three girls,” ages 8 and under, Mr. Collum said. “If they came to me and said, ‘Hey, Daddy, I want to do what you do.’ Would I steer them away from it? Yeah, I probably would.”

Updated: 4-21-2021

Oil Extends Losing Run on Demand Concerns, U.S. Stockpile Gain

Oil fell for a third day after data showed a rise in U.S. stockpiles and investors fretted over an uneven recovery in global demand, with India reporting a record one-day surge in Covid-19 cases above 300,000.

West Texas Intermediate shed 0.5% following a fall on Wednesday, when government figures showed the first rise in American stockpiles in a month. The flare-up in coronavirus cases in India, the third-largest oil importer, is hurting consumption, with curbs reimposed in major cities. That’s offsetting positive signals on demand from other economies including China and the U.S.

Crude’s run of losses is threatening to push prices back toward $60 a barrel, eroding gains last week that were underpinned by positive forecasts for worldwide energy demand from the International Energy Agency and Organization of Petroleum Exporting Countries. U.S. futures are still up by more than 25% this year, however, while global benchmark Brent remains backwardated, a bullish pattern that suggests an underlying resilience.

“Asia, especially India, is becoming the epicenter of all fears surrounding demand,” said Steve Innes, chief market strategist at Axi. Still, “macros are pretty strong globally,” he added, flagging prospects for improved consumption over the northern hemisphere summer, aided by U.S. driving season.

The U.S. figures showed a surprise addition of 594,000 barrels to nationwide stockpiles. However, the rolling four-week average for oil products supplied ticked higher, and the same snapshot for gasoline rose to 8.93 million barrels a day, about half a million barrels shy of the same week in 2019.

The global picture — and prospects for near-term energy demand — are mixed. While vaccination drives are prompting greater activity and rising mobility in the U.S. and parts of Europe, the pandemic is tightening its grip elsewhere. More people were diagnosed with Covid-19 last week than in any other since the outbreak began, led by the rocketing numbers in India.

Highlighting the grim situation in South Asia, India on Thursday reported a record 314,835 fresh cases, with no sign yet of the brutal wave of infection abating. The surge has forced the nation’s financial and political capitals — Mumbai and New Delhi — to impose restrictions on movement.

Even as India is facing a crisis, however, other countries are mapping out plans to open up in a potential boost to oil demand. Among them, France will lift curbs on regional movement and reopen schools in coming weeks, and Greece will ease most lockdown measures in May ahead of its reopening to tourism.

Banking on a pick-up in demand, the OPEC+ alliance is planning to relax its deep supply curbs from May through to July. Despite these extra barrels, there is still expected to be a drawdown in global inventories, supporting prices, Australia & New Zealand Banking Group said in a report.

Brent’s prompt timespread was 64 cents a barrel in backwardation, up from 40 cents at the start of April. That’s a bullish pattern, with near-term prices trading above those further out.

Updated: 4-23-2021

Oil Frackers Struggle With Ways To Appease Investors

Executives would be advised to stick to a script heavy on discipline, deleveraging and dividends.

Granted, after a catastrophic 2020 — capping off a dismal decade — plaudits for a months-old rebound may seem a tad premature. Yet with earnings season about to kick off, the exploration and production sector has a decent chance of this run continuing — provided the companies don’t talk themselves out of it on those earnings calls.

Despite the rally so far, valuations do not look particularly stretched.

They look even more sedate when you compare them to the broader market after its curiously sprightly plague year.

Crowd Pleader

The E&P sector remains deeply out of favor compared to the broader market.

There are good reasons for the frackers’ relative unpopularity, namely a history of burning cash and a future clouded by climate change. But there are signs of companies addressing the former, with drilling only making a cautious return as oil prices have recovered from Covid-19 (at least among listed E&P companies).

Climate change is still there, of course, with methane emissions particularly in focus and the current U.S. administration going all in on decarbonization. In the near term, however, oil demand is still 95 million barrels a day and rising.

This week marks the one-year anniversary of Nymex oil futures closing in the red for the first time ever. The great thing about hitting rock bottom — or even drilling beneath rock bottom — is the eventual year-over-year comparisons: Oil’s up roughly $100 a barrel since that day in April 2020. Consensus E&P earnings forecasts for 2021 have doubled since early January.

And while Covid-19 still stalks us — especially in critical markets such as India — the likelihood is that oil prices will strengthen further in the second half of the year provided OPEC+ hangs together.

First-quarter earnings themselves may be noisy, with February’s Texas freeze likely impacting earnings and hedges inflicting losses on some as oil prices have rallied. More important than this, however, will be what the companies say.

For the rally to continue, either multiples need to expand or earnings expectations need to rise further. The former aren’t stretched but also aren’t deeply discounted. There is room for improvement with the latter, however. Forecasts are likely to be priced off the crude oil futures strip, about $59 a barrel. As oil demand likely strengthens through the summer, higher prices should feed through to earnings upgrades, lifting stocks.

What could work against that is any sign of companies taking strength in oil prices as a signal to spend more. This is a market that wants E&P capital preserved or paid out. The most recent attempt to bring some in, the IPO of Vine Energy Inc. in March, was not exactly met with open arms. Any sign of reverting to type is liable to feed through to a lower multiple.

At these levels, just a half-turn less on cash flow would wipe out the benefit of a 12% increase in cash flow forecasts, all else equal. So when executives start taking questions next week, they would be well advised to stick to a script heavy on discipline, deleveraging and dividends; not so much on drilling.

There was a good portent of that earlier this week in the form of Halliburton Co.’s earnings call. CEO Jeff Miller’s comment that “there is a lot of discipline around production” in the U.S. wasn’t helpful for his own company’s stock, which fell almost 4% on the day.

Halliburton, along with other oilfield services contractors, tends to do better when the frackers are in a froth. Its lack of pricing power is a sign E&P companies are staying cautious. Do that long enough, and not only will earnings rise — they might tempt back enough investors to juice those multiples too.

Updated: 5-11-2021

Few Signs of Recovery For U.S. Oil Production, OPEC Says

Producers also leave 2021 world oil demand forecast unchanged as ‘uncertainties persist’.

American oil production is set to drop again this year, with the shale industry’s output showing few signs of recovery despite a broader pickup in economic activity, the Organization of the Petroleum Exporting Countries said Tuesday.

In its closely watched monthly market report, OPEC cut its forecast for the amount it expects production from its noncartel counterparts to increase in 2021 by 200,000 barrels a day to 700,000.

Canada, Norway, Brazil, and China will drive that overall increase, but persistently low capital expenditure and the unexpected winter storm that Texas suffered in February mean U.S. supply is expected to fall by 100,000 barrels a day this year after dropping 800,000 barrels a day last year, the cartel said.

Despite its forecast for a rise in supply from outside the cartel this year, OPEC said in its report that “uncertainties persist particularly with regard to levels of investment which is expected to determine the non-OPEC supply outlook for the years to come.”

Oil prices swung between small gains and losses before closing slightly higher on Tuesday as traders weighed signals that the Colonial pipeline—hit last week by a ransomware attack that threatened its ability to supply oil products to the U.S. East Coast—could have most or all of its regular service restored by the end of this week.

Brent crude oil, the global benchmark, ended the day up 0.3% at $68.55 a barrel and West Texas Intermediate futures, the U.S. benchmark, added 0.6% to $65.28 a barrel.

In its report, OPEC left unchanged its forecast for global oil demand in 2021. The cartel estimates consumption will rise by 6 million barrels a day this year to average 96.5 million barrels a day, leaving demand 3.5% lower than it was before coronavirus pandemic restrictions shut factories, grounded planes and kept people at home.

The world’s post-pandemic economic recovery, which has also prompted a rebound in oil demand, has varied in recent months due to governments’ differing levels of success in keeping coronavirus case numbers at bay and rolling out vaccination programs.

While India and Brazil have suffered a resurgence of cases in recent months, the U.S., China and parts of Europe such as the U.K. have all succeeded in bringing infections under control and lifting travel restrictions. Despite that fast-changing and uncertain backdrop, OPEC raised its forecast for global economic growth in 2021 by 0.1 percentage point to 5.5% after a 3.5% contraction in 2020.

OPEC and its allies agreed early last month to boost their collective production by more than 2 million barrels a day over May, June and July as they wagered on resurgent demand as the pandemic ebbs in parts of the world.

Secondary data cited by OPEC show that production from Saudi Arabia and Nigeria rose in advance of the easing of those restrictions, while Libyan production slipped after disputes over budget payments prompted the country’s national oil company to declare force majeure and cut production.

According to the data, Iranian supply continued to rise, climbing 73,000 barrels a day to 2.4 million barrels a day, with growing Chinese imports potentially threatening the West’s leverage in talks over reviving a nuclear deal with Tehran.

Meanwhile, front-month Nymex natural gas for June delivery gained 2.30 cents per million British thermal units, or 0.8%, to $2.9550 per million British thermal units today.

Updated: 6-14-2021

Oil Price Hits Pandemic High As Investors Bet On Green Energy

Wall Street’s preference for renewables could mean oil producers will now struggle to meet demand.

Some investors are wagering that Wall Street’s preference for green energy will depress spending on oil extraction, setting the stage for supply shortages and higher fuel prices.

The bets come as money managers line up trillions of dollars for wind, solar and other renewable programs and expenditures on oil projects tumble. The drop in fossil-fuel spending is becoming so severe that energy companies could struggle to quench the world’s thirst for oil, some analysts say.

Crude is still expected to remain in high demand over the next decade to make transportation fuels and petrochemicals used for plastics and other household products. U.S. consumption has surged lately following the worst of the coronavirus pandemic, and output cuts by the Organization of the Petroleum Exporting Countries have given prices a further boost.

.S. crude hit $71.48 a barrel Monday, its highest level in more than 2½ years, and has roughly doubled since the end of October. Some traders are using options, which allow the holder to buy or sell an asset at a specific price in the future, to wager on prices hitting $100 by the end of next year.

Even after OPEC and its allies lift output in the months ahead, some analysts think production will struggle to catch up to demand, which the International Energy Agency projects will rise at least through 2026. Spending on oil extraction fell last year to about $330 billion, less than half the total from its 2014 record, according to research firm Wood Mackenzie. That figure is expected to rise just modestly this year and in the years ahead.

Leigh Goehring, managing partner at commodities-focused investment firm Goehring & Rozencwajg Associates, said he thinks prices will soar in coming years as consumption tops production capacity for a sustained period for the first time ever. His firm lifted its investments in energy producers during last year’s crash and has maintained those holdings.

“This is the basis for the next oil crisis,” he said. “We’re in uncharted territory.”

Analysts say an oil-price surge could happen like this: As more people resume travel following the pandemic, demand is expected to rise. That would allow OPEC to ease supply restrictions and lower global inventories of crude. If consumption continues climbing beyond 2022 as many expect, the world would then need more oil from the same companies currently being told by investors to limit spending, resulting in a supply shortfall.

OPEC has the ability to quickly increase production, and there are currently ample reserves that could be tapped to respond to price spikes. But many on Wall Street are retreating from the fossil-fuel industry, leaving investors questioning whether companies would be able to raise enough money to fill any longer-term supply gaps.

In recent years, growing output from U.S. shale producers and giant oil companies suppressed prices. Now, many analysts doubt that these companies will rapidly beef up spending in the face of industry consolidation and mounting environmental pressure. Energy firms have recently slashed the value of their assets by tens of billions of dollars as the sector copes with last year’s wave of bankruptcies and project setbacks.

Planned investment in oil supply globally falls about $600 billion short of what will be needed to meet projected demand by 2030, according to JPMorgan Chase & Co. analyst Christyan Malek. Pressure to deliver cash to shareholders, partly driven by worries about the long-run outlook for oil demand, has limited the industry’s ability to plow money into new projects, he said.

“It’s just hard to see where the capital is going to come from to grow at a rate that will be needed from 2022,” said David Meaney, founding principal of Assert Capital Management LP. The Dallas-based hedge fund is positioning for higher oil prices through futures and options.

The wagers are a reminder that the unprecedented transition to renewables and electric vehicles is still in its early stages and could go through several phases. It also shows the challenges facing producers like Exxon Mobil Corp. , Chevron Corp. and Royal Dutch Shell PLC. In addition to concerns about spending and shareholder returns, they are contending with mandates to limit environmental damage. Shell said last week that it would accelerate efforts to cut emissions following a Dutch court ruling ordering the company to take more drastic action.

As the economy recovers from the pandemic, the question confronting the energy industry is whether demand will eventually fall to match limited supplies, investors say. That reverses a decadeslong paradigm of wondering if production can catch up to consumption, with Wall Street debating uncertain estimates about the speed of the renewable transition.

“I’m bullish on electric vehicles. It still takes time before they can take a meaningful chunk out of oil demand,” said Jason Bordoff, a former Obama administration energy adviser and the founding director of Columbia University’s Center on Global Energy Policy.

Another obstacle for producers: declining output from existing wells over time. The number of rigs drilling for oil in the U.S. remains about 60% below levels from the end of 2018 even as prices have surged, figures from Baker Hughes show.

“Investors have made it clear to the energy sector: ‘Don’t spend a lot of money,’” said Rob Thummel, senior portfolio manager at energy asset manager Tortoise. “Boards and management teams have to listen to the shareholders.”

The energy industry isn’t alone in its cautious approach. Miners, which burned through cash the last time industrial metals prices shot higher, have also been reluctant to drive money into projects because investors have encouraged greater discipline.

Some analysts argue that concerns about a dearth of oil are overstated, particularly when large suppliers are still intentionally withholding copious amounts due to coronavirus disruptions. Producers and investors might be less disciplined in limiting capital spending and supply if prices surge and they could profit, they say.

But for now, many are positioning for shortages. Hayal Ahmadzada, chief trading officer at the trading arm of Azerbaijan’s national oil company, drives a Tesla Inc. electric car but expects crude to rise above $100 a barrel next year.

“The transition has to be very careful to avoid the big disruptions,” he said.

Updated: 6-17-2021

After Blowing $300 Billion, U.S. Shale Finally Makes Money

Marathon Oil Corp. used to represent everything that was wrong with U.S. shale: enormous debtloads, lavish executive pay and a seeming willingness to spend whatever it took to boost output. The company hemorrhaged money, and the stock plunged 84% from a peak in 2014 through the end of last year.

This year, CEO Lee Tillman took a different tack. He cut his own pay 25%, got rid of its corporate aircraft and with oil output down 20% after the pandemic, pledged to leave it there. The result? The stock doubled this year. Its peers are doing well too. U.S. wildcatters are the second-best performing sector in the S&P 500 Index.

After years of booms and busts that produced astronomical losses along with a whole lot of oil, the fracking industry seems to have found a sweet spot. It’s poised to generate more than $30 billion of free cash this year, a record, according to Bloomberg Intelligence.

While that’s just a blip compared with the $300 billion that Deloitte LLP estimates the sector burned over the previous decade, it marks at least a temporary revival for an industry that a year ago had been largely written off by investors.

For sure, frackers have benefited from the 50% run-up in global oil prices this year as demand roars back in places where the pandemic has receded. Just as important to their bottom lines, though, has been the ability to hold back on new supply, to avoid drilling the more marginal wells they would have in years past. They’re saving cash instead of spending money to ramp up output at all costs.

It’s a turnaround from the early days of the shale revolution a decade ago, when new horizontal drilling and hydraulic fracturing techniques unlocked vast oceans of crude from rock previously considered impermeable, loosening the OPEC cartel’s grip on global production.

Back then, with oil trading over $100 a barrel and global concerns of shortages, lenders and stock investors rewarded companies for high production. Profits would naturally flow later, so the thinking went. But the industry was a victim of its own success, pumping more oil than anyone needed.

“The shale boom oversupplied the world and crushed prices,” Dan Pickering, founder and portfolio manager at Pickering Energy Partners in Houston, said in an interview. “Shale is not going to do that in 2022 and 2023. It’s cautious optimism, the feeling that ‘the worst is past.’”

The key to the transformation? A lot less oil. Shale’s first era from 2010 to 2014 was marked by explosive growth fueled by the technology breakthrough, and the second stage from 2015 to 2020 saw prices fall but output soar amid heavy spending. Now Shale 3.0, as some investment banks have called it, is all about free cash flow.

The U.S. is pumping about 1.9 million fewer barrels a day since Covid-19 caused prices to tumble last year, a reduction that’s bigger than Nigeria and Venezuela’s production combined.

That’s bad for consumers — creating higher prices at the pump — and is a boon for the producers of OPEC+ as it gives the coalition led by Saudi Arabia and Russia more room for maneuver to bring back their own production. But it’s also set the domestic shale industry on a more sustainable path, directly to the benefit of equity and bond investors.

“From a financial perspective, shale is entering a new, better era, with higher profitability,” said Elisabeth Murphy, ESAI Energy LLC upstream analyst for North America.

For much of the past decade, shale producers spent every dollar they earned and borrowed extra to drill new wells. Producers would typically reinvest 120% to 130% of their operating cash flow in new production, according to Noah Barrett, a Denver-based energy analyst at Janus Henderson. Now, that figure is closer to 70% or lower, leaving plenty of cash for shareholder payouts.

Marathon, for example, expects to generate $1.6 billion of free cash flow from just $1 billion of capital spending, allowing the company to raise its dividend and reduce debt, the culmination of a plan than began in 2017.

The optimism is also apparent in the bond market, where an index of junk-rated independent U.S. oil producers has returned 10% this year — three times the average for high-yield companies — as borrowing costs fell to a record.

Consolidation is also helping the industry. Devon Energy Corp. merged with WPX Energy Inc. earlier this year to cut costs. The combined company is producing 8% less oil than a year earlier and has promised to pay a variable dividend on top of its regular payout.

Pioneer Natural Resources Co. has completed two deals this year and says it will cut growth rates from both acquired companies.

There’s a risk that the discipline among shale producers may start to weaken if oil prices remain above $70 a barrel, particularly for companies that have used the last six months to pay down debt. The price needed to break even on a well in the Permian is only $35 to $45 a barrel, according to Rystad Energy.

“Once internal price forecasts reach breakeven cost levels, these same executives have a fiduciary duty to allocate capital and resources to produce increasing volumes of oil and gas,” said Charles Kemp, vice president at Baker & O’Brien, a consultancy. “If they don’t, someone else will.”

At current prices, drillers may be able to invest more in 2022 while still rewarding investors. IHS Markit Ltd., a consultancy, estimates that the U.S. shale industry is on track to hike spending from $58 billion in 2021 to $80 billion in 2022.

“The early signs are that discipline is holding, but we still need to watch this pretty closely,” said Jeff Wyll, a senior analyst at fund manager Neuberger Berman, which has about $400 billion of assets under management. “There’s a hyper sensitivity toward any company that’s shifting back toward growth mode.”

An example came in February, when EOG Resources Inc., the biggest independent shale producer, signaled plans to boost production by as much as 12% in 2022. Retribution was swift. The shares tumbled 8.5% the next day, wiping out $3.5 billion of market value.

Updated: 6-22-2021

Shale’s 400% Rise In Frack Crews Not Enough To Boost Output

Even a more than 400% jump in the number of fracking crews working the U.S. shale patch isn’t enough to send oil output soaring. In fact, it’s just enough to keep production relatively flat this year, according to Primary Vision Inc., which has tracked data on frack crews since 2013.

After an 85% tumble in the number of crews completing wells during the depths of the pandemic, the figure has steadily recovered over the past year. It now stands at 235, up from 45 on May 22, 2020. That could grow by roughly another 6% to 250 crews by year end, Scott Levine, an analyst at Bloomberg Intelligence, wrote last week in a report.

But because of the way well production decreases over time, the jump in crews is only enough to keep output flat, rather than boosting it.

“Operators are still focusing on getting out of 2021 with a little bit better managed expectations and better hedge profile,” Matt Johnson, chief executive officer of Primary Vision, said Tuesday in a joint webcast with Bloomberg Intelligence forecasting the pressure-pumping market. “Where is that relative to the actual production? We’re pretty close to managing it at this point.”

Because shale wells see steep declines early in their life of production, the U.S. oil market requires more wells to be drilled and completed in order to replace them and hold output constant. After dramatically turning off activity last year due to history’s worst crude crash, the oil service companies had to ramp up frack crews in order to get new production back online. The mantra among shale’s biggest explorers is to keep output relatively flat this year and send profits back to shareholders.

Updated: 6-23-2021

Cash Flow of World’s Oil Drillers Heads For Record $348 Billion

The world’s publicly traded independent oil producers will make record profits this year, surpassing the levels reached when crude hit an all-time high near $150 a barrel more than a decade ago, according to Rystad Energy.

Combined free cash flow from the sector is expected to surge to $348 billion, beating the previous high of $311 billion in 2008, Rystad said. Key to the turnaround is U.S. shale, with the industry expected to reverse years of losses in 2021 and make “super profits” of nearly $60 billion of free cash flow before hedges.

Surging oil prices will add to producers’ revenue, but profits will be super-charged by executives determined to constrain capital spending on new output, the Oslo-based consultant said in a note authored by Espen Erlingsen, head of upstream research. This is the opposite of previous cycles, when crude rallies prompted companies to spend heavily on exploration and production in search of fresh supplies.

But the forecast raises questions about how disciplined producers will remain about keeping output in check as the surge in crude prices drives outsized profits. So far, explorers have largely heeded investor pressure to rein in spending and return cash to shareholders. While the industry’s revenue is expected to jump 55% in 2021 from last year, capital investment will only increase 2%, Rystad said.

All the money sloshing around may spur more mergers and acquisitions, however, with transaction values already up 30% on last year, the research firm said. Brent oil prices are up 46% this year to trade above $75 a barrel, with some traders and executives seeing the possibility of a rally to $100.

Updated: 6-29-2021

How Last Century’s Oil Wells Are Messing With Texas Right Now

Ranchers and regulators are contending with uncontrolled leaks from thousands of abandoned oil and gas sites that could render some land “functionally uninhabitable.”

Ashley Watt is nothing if not a friend of fracking. She’s invested in mines that supply the sand frackers blast into the ground. Her family owns a ranch larger than Manhattan that’s home to hundreds of oil and natural gas wells. Her Twitter handle is “Frac Sand Baroness.”

That’s what made it all the more jarring almost three weeks ago when Watt began publicly railing against one particular oil driller for leaks on her land. Noxious wastewater from oil drilling began leaching across the ground, endangering people and livestock.

By her count, the pollution has killed four cows and two calves so far. Chevron Corp., which drilled the 1960s-era wells that polluted Watt’s land, brought in earth-moving equipment and a well-control crew, even though it had sold most of its interests there years ago. It took 10 days to halt the first leak. Given the hundreds of other aging wells dotting the land, it’s done little to put Watt’s mind at ease.

“I am not anti-oil industry,” Watt said in an interview. “That is the economy here. It’s a good business.” At the same the same time, she said, “We have to be responsible stewards. If we can’t do it right here in the Permian Basin, then how can we do it right anywhere? Nobody should let us in if we’re going to act like this.”

And just like that, Watt — whether she liked it or not — became an ally to scores of environmentalists and activists who’ve been warning for years that America is on the verge of an environmental disaster. Long before the advent of shale drilling techniques that fueled the greatest move toward energy independence the nation’s ever seen, conventional oil explorers left the country pierced with millions of defunct wells that are aging by the day and increasingly springing leaks.

“There’s this enormous backlog” of abandoned wells, “and we don’t have financing in place to clean them up,” said Daniel Raimi, a fellow at the non-profit research group Resources for the Future. “We’ve seen very clearly that existing regulatory structures, particularly at the state level, have not properly incentivized companies to clean up their infrastructure.”

There are 3.4 million old crude and gas wells in various states of abandonment across the U.S., an almost 20% increase in the past decade, according to the Environmental Protection Agency. Less than half of those holes have been plugged, EPA figures showed. In all, the wells are spewing about 7 million metric tons of methane into the atmosphere every year, although unplugged wells tend to be 100 times more polluting than their plugged brethren.

Methane releases from abandoned gas wells have been particularly egregious, growing by 40% in the past three decades. As the energy industry pivots away from fossil fuels to combat climate change, the inventory of untended wells will only expand.

Abandoned wells have become so thorny an issue in longtime oil states like Pennsylvania that President Joe Biden included $16 billion in his infrastructure package to put laid-off roughnecks to work plugging old wells and mines. Federal lawmakers including Senator Elizabeth Warren of Massachusetts have meanwhile blasted the Bureau of Land Management for failing to hold the oil and gas industry accountable for plugging millions of abandoned wells on public lands.

In Texas, the nation’s largest source of oil, companies plugged almost 8,900 wells in the last fiscal year, and have sealed another 5,700 so far this fiscal year, according to the Texas Railroad Commission that oversees the oil and natural gas industry.

The agency requires cement barriers through sections of a well that go through aquifers, but the commission doesn’t track how many of them spring leaks. The regulator documented more than 500 industry-related spills and accidents last fiscal year, with equipment failure and corrosion listed as the top two causes.

For it’s part, Chevron said in a statement that its priorities on Watt’s property “are protecting people — including Ms. Watt and our workforce onsite, protecting the environment, plugging the well and remediating impacts.” Industry experts estimated the cleanup is costing Chevron more than $250,000 a day, though the company has declined to disclose its expenses. The company also helped Watt relocate 500 cows and trucked in fresh drinking water for her family and ranch workers.

Despite all of Chevron’s efforts, Virginia Palacios, executive director of the watchdog Commission Shift based in Austin, Texas, calls old wells like the ones on Watt’s property “ticking time bombs.” Her group has fought for tougher regulations to ensure drillers continue to monitor their operations long past the day they stop yielding oil.

“We need to plan to monitor these wells in perpetuity,” she said. “Even if you plug these wells, as we have seen in this incident, they can still cause environmental damage and pose a risk to human health.”

Prior to the 1950s, the rules in Texas for taking wells out of service were so vague that they were sometimes plugged with brush, wood, rocks, paper and linen sacks, or any other item that could hold cement, according to a report from the National Petroleum Council, an industry group that advises the U.S. Energy Department. Last year, the railroad commission was sued by Public Citizen and two South Texas landowners over its alleged failure to responsible management of some abandoned, unplugged wells.

“There are hundreds of wells on this ranch alone,” Watt said. “Extrapolating thousands of wells in the Permian Basin, tens of thousands, how many of those are going to collapse? Even if it’s only 1%, that’s going to pollute aquifers and destroy a huge swath of land. That’s enough to make the Permian Basin functionally uninhabitable in 50 years.”

After more than two weeks, the exact cause of the leak is not yet clear but experts hired by Watt pointed to tiny perforations in a cement plug installed in the mid-1990s to permanently take the well out service. It’s a routine industry practice to pour cement down wells when production peters out and they no longer turn a profit. Most of the time, such plugs hold fast.

But with other decades-old wells and pipes leaking on her property, Watt believes an environmental disaster is unfolding not just on her family’s land but also elsewhere in the Permian Basin, the vast oilfield that’s been a drilling hotbed for more than a century. Watt fears that legacy wells, neglected equipment and lax enforcement by state regulators are a recipe for disaster.

“Will this be inhabitable land in 100 years, if all of our old wellbores are collapsing underneath us?,” Watt said after traversing the 22,000-acre ranch in a brown Ford F-150 pickup truck. “I don’t know and, frankly, that’s terrifying,”

The Watt family arrived in remote West Texas early in the 20th century when Ashley’s great-grandfather quit a job at the Fort Worth Stockyards to begin ranching a decade before the first Permian oil boom in the 1920s. In the mid-1990s, her parents bought the nearby Antina property, a swath of sand hills and desert grasslands that provide excellent feed for cattle. Her folks’ ashes are scattered among the dunes.

Roughly a dozen wells are still trickling out crude and gas, while the rest were all plugged decades ago. It’s those legacy wells and the pipelines attached to them that concern Watt. The former U.S. Marine Corps captain who flew drones over Afghanistan is using those skills to scour her land for the telltale signs of other leaks.

Among her findings was a 1950s-era well that’s leaking crude; Chevron is also cleaning up that site. She also found a natural gas pipeline that became exposed when sand dunes shifted and spewed gas underground. In another location, she discovered broken storage equipment that was releasing gas into the atmosphere.

Watt and her attorney Sarah Stogner took to social media to highlight the scope of the pollution. In one Tweet, they showed a cleanup crew’s ad hoc method of slowing a wastewater leak by placing a red plastic bucket atop a length of pipe. Red bucket memes exploded across Twitter’s energy-industry subculture. In another, Watt invited Chevron CEO Mike Wirth to visit and “come get some sand in your Gucci loafers.”

Chevron hired Cudd Well Control, a legendary oilfield outfit famous for snuffing out the late Saddam Hussein’s fiery blowouts in Kuwait, to help with the cleanup.

Yeah that should fix it.

A big thank you to Red Bucket Well Control LLC! pic.twitter.com/YRdRCMzMHe

— Frac Sand Baroness (@sand_frac) June 13, 2021

“It’s important for the Railroad Commission and other agencies to understand that we need to plan to monitor these wells in perpetuity,” said Commission Shift’s Palacios. “Even if you plug these wells, as we have seen in this incident, they can still cause environmental damage and pose a risk to human health.”

Adding more cement to key areas during the plugging process and testing could easily reduce risk, said Tom Slocum, a well-plugging expert and vice president with consulting firm Trifecta Solutions.

“This is a cheap insurance policy,” Slocum said. “For an extra $1,000 to $1,500 of cement, a little bit more time and a couple hundred bucks for testing the cement plug, you can avoid a catastrophe.”

Updated: 7-2-2021

High Oil Prices Send U.S. Refiners Scouring For Alternatives

Skyrocketing crude oil prices have prompted cash-strapped U.S. refiners to look for alternative ways to maximize gasoline production during the peak of the summer driving season.

The fuel-makers are buying low-sulfur vacuum gasoil, or VGO, from abroad as a more economical option to maximize fuel production without increasing crude intake. As a result, VGO prices are at the highest since October 2018, with imports coming to the U.S. from as far as the Black Sea to meet demand.

“This year in particular with gasoline demand expected to be stronger than middle distillate, diesel, gasoil, jet, you could see refiners opt to import VGO to run through a cat cracker if the price is right,” Chris Barber, principal analyst at ESAI, said by email. “It would allow them to produce gasoline without a lot of additional diesel or middle distillate.”

More than a year after the pandemic decimated fuel markets gasoline demand is recovering, with pump prices at a seven-year high as Americans return to offices and embark on summer road trips. Refiners are facing a limited window to capture profit and build up gasoline inventories ahead of what could possibly be a severe hurricane season that could lead to unplanned shutdowns.

With crude futures up about 50% so far this year, refining centers from Delaware on the East Coast to all along the Gulf Coast, from Pascagoula, Mississippi, and Texas City, Texas, are importing VGO, shipping data compiled by Bloomberg show. West Texas Intermediate futures were trading near $75 a barrel in New York on Friday.

That popularity of VGO imports may subside soon. VGO is worth about $81 a barrel, about $6 more than West Texas Intermediate futures. Consequently, refiners may be less likely to buy VGO and instead rely on their crude units to make the feedstock.

Soaring crude values have decimated crude topping margins globally, according to London-based consultancy Energy Aspects. Meanwhile, conversion unit margins like those from fluid catalytic crackers (FCCs) remain strong, buoying feedstocks demand from refineries seeking to leverage those units.

“Refiners will seek to extract margin as much as possible, from lower cost feedstocks than crude to these specific complex units,” said Zachary Rogers, director for Global Oil Service at Rapidan Energy Group.

The potential for profit from using VGO remains strong. Prompt cash-market gasoline in Houston for shipment on the Colonial Pipeline, which spans the eastern part of the country, was trading about 25 cents per gallon higher than the feedstock late this week.

Updated: 7-9-2021

American Frackers Show Restraint As Oil Tops $70

Shale companies, flush with cash, are paying off debt and sharing with investors rather than drilling more

Shale companies pumped with abandon anytime oil prices rose sharply last decade. But as crude tops $70 a barrel, they are barely doing enough to sustain U.S. production.

Frackers have been forced to rein in spending and live within their means after many investors lost faith in the companies following years of poor returns, lenders reduced their credit lines and capital markets showed little interest in funding expansive new drilling campaigns.

The result is that shale drillers, which in the past have played the role of the oil world’s swing producer by quickly increasing output to meet demand, are largely standing pat for now, as the reopening of Western economies leads to a resurgence of global oil and gas prices.

The companies are raking in more cash than ever. Public shale companies that drill primarily for oil collectively generated a record $4.1 billion in free cash flow in the first quarter of 2021 and are poised to take in almost $15 billion for the year if prices remain higher, according to consulting firm Rystad Energy.

But instead of pumping that money back into drilling as they have historically done, large producers such as Occidental Petroleum Corp. and Ovintiv Inc., the company formerly known as Encana Corp., have said they plan to focus on reducing debt, keeping U.S. output flat.

Other sizable shale drillers such as Pioneer Natural Resources Co. and Devon Energy Corp. are socking away money to return to investors in the form of variable dividends, one of the enticements they want to use to lure more investors back.

“We’re producing all this free cash flow, but it’s not going out to investors yet,” said Scott Sheffield, chief executive of Pioneer, noting that many companies are focusing on debt before they return cash to investors. “There’s no reason for them to buy into this sector at this point in time.”

Even as oil prices reached their highest level in six years last week, many drilling rigs remain idle. The U.S. is producing roughly 2 million barrels a day less than it was before the pandemic.

The number of active rigs drilling for oil rose by two this week and stands at 378, down from 683 pre-Covid-19, according to oil-field services firm Baker Hughes Co. Shale companies have dipped into their stash of drilled-but-still-dormant wells to help maintain output cheaply.

If shale companies don’t add more rigs, U.S. oil production could fall by the end of the year, said Shaia Hosseinzadeh, a managing partner of OnyxPoint Global Management LP. The investment firm estimates that 450 rigs are needed to maintain current oil production levels and 575 rigs are needed to get it back to pre-Covid-19 levels. The problem for fracking companies, Mr. Hosseinzadeh said, is that they can’t access cheap capital any longer.

“Fossil fuels will need to produce a disproportionately higher rate of return to compete for capital with other sectors of the economy,” he said.

While shale companies are showing restraint for now, some analysts predicted they could increase spending and output if prices climb.

In the heyday of the shale boom, publicly traded oil producers typically reinvested more than 100% of the cash flow they made from operations back into drilling campaigns. Now they are using about half of the income they generate on new drilling and are only growing output slightly, if at all.

Devon Chief Executive Richard Muncrief said in an interview that the Oklahoma-based driller will reinvest about 45% of its operational cash flow, down from about 60% a few months ago as oil prices have risen.

That discipline has attracted some investors that haven’t traditionally invested in energy to Devon—seeking energy exposure as prices rise, and drawn by Devon’s variable dividend, he said.

“Some are names our investor relations folks weren’t all that familiar with, but they’re managing quite a bit of money,” Mr. Muncrief said.

Shale companies had about $148.6 billion in debt coming into the year, according to energy consulting firm Wood Mackenzie, and much of the cash they are collecting is going toward that debt pile. Securing new capital is increasingly difficult for many.

Many large U.S. banks have cut their energy lending, and some European ones such as Deutsche Bank AG and Société Générale SA have exited fossil fuel financing altogether. Loans backed by companies’ oil and gas reserves, a lifeline for smaller drillers, have shrunk, leaving drillers to explore more expensive financing.

Laredo Petroleum Inc., Centennial Resource Development Inc. and Callon Petroleum Co. CPE 1.99% saw the amount of money banks would lend to them on their revolving lines of credit cut about 24%, 42% and 36% respectively, during the pandemic. Lenders didn’t increase their borrowing bases this year, despite higher energy prices.

Callon said it would cut its 2021 capital expenditures to $430 million, a 12% reduction from its 2020 budget. In 2019, it spent $515 million. As a result, the company said it would produce about 90,000 barrels of oil and gas a day in 2021, down from more than 101,000 barrels a day in 2020. Callon said it is focused on reducing its roughly $3 billion in debt. The company declined to comment.

As U.S. oil prices have risen more than 50% this year to above $70 a barrel, shale company shares have climbed as well. The market capitalization of the 25 largest independent U.S. oil producers has nearly doubled this year to about $360 billion, according to data from S&P Global Market Intelligence. By comparison, the S&P 500 index has risen about 18% this year.

Still, with a few exceptions, energy stocks have only essentially recovered to where they were before the pandemic. Energy stocks are trading at half of the price-to-book ratio that they averaged from 1928 through 2009, before shale drilling became prevalent, according to Empirical Research Partners LLC.

“Public equity investors have tired of the oil price volatility,” said Todd Dittmann, head of energy at hedge fund Angelo Gordon & Co. “They want cash now, whether from buybacks or regular or special dividends.”

Updated: 7-26-2021

Big Oil Companies Push Hydrogen As Green Alternative, But Obstacles Remain

BP, Shell want to make the gas using renewable energy, but doing so remains expensive

Big oil companies have long touted hydrogen energy as a way to reduce carbon emissions. Now they are grappling with how to make that a reality.

BP PLC, Royal Dutch Shell PLC and TotalEnergies SE are all pursuing multimillion-dollar hydrogen projects, often with government support, as they seek to redefine their future role in a world less reliant on fossil fuels. Hydrogen made using renewable energy can be produced and used without emitting carbon dioxide.

Still, experts say there are various hurdles to the light, colorless gas fulfilling its potential. Firstly, most hydrogen today is made from fossil fuels, primarily natural gas. The challenge is to make it using renewable power instead and produce it on an industrial scale, in the hope of bringing down costs. Additionally, hydrogen is explosive, as well as difficult to store and transport.

Oil companies are pursuing green hydrogen, which they see as a longer-term goal, while also looking at applying carbon-capture technology to fossil-fuel-based hydrogen production as a way to clean up the gas in the interim.

As of the end of June, there were 244 large-scale green hydrogen projects planned, according to the Hydrogen Council, an industry group, up more than 50% since the end of January. It estimates tens of billions of dollars have already been earmarked for hydrogen projects.

Historically used to help make fertilizer and chemicals, hydrogen is increasingly being pushed for a much broader range of uses, including for trucks, planes, ships, household heating and as a way to store renewable power.

“Today, hydrogen is used as a feedstock primarily…the growth of the hydrogen market is all about it becoming an energy source,” said Louise Jacobsen Plutt, BP’s senior vice president of hydrogen and carbon capture and storage.

BP is exploring the use of hydrogen to replace natural gas in industries such as steel, cement and chemicals, and also as a substitute for diesel in trucks. Overall, BP forecasts hydrogen could account for about 16% of the world’s energy consumption by 2050—if net zero carbon-emissions goals are to be achieved—up from less than 1% today.

Like other major oil companies, BP thinks its existing expertise—it already produces hydrogen at refineries—and infrastructure could help it win a sizable market share. Last year the company said it planned to use wind power to produce hydrogen for a refinery in Germany, hoping to demonstrate the technology at a large scale.

However, BP doesn’t expect green hydrogen to be a material part of its business until the 2030s, and it has yet to make a final investment decision on any new hydrogen projects. It will take time to create a market and bring down the cost, Ms. Jacobsen Plutt said, “Because it is so nascent, it is more expensive.”

Shell also is grappling with high costs. This month, the company started up what it said is Europe’s largest green hydrogen plant, to supply its Rhineland refinery in Germany. But that hydrogen is between five and seven times more expensive than the fossil-fuel-based product it predominantly uses.

“You’re not in the money yet,” said Paul Bogers, Shell’s vice president of hydrogen. “For green hydrogen, the core belief is that you almost have to get to a world where the electrons are free.”

Industry executives say green hydrogen is expensive because of the cost of the electricity needed to make it, as well as the cost of the electrolyzer—the system used to split water into hydrogen and oxygen.

Shell hopes it can reduce costs by building hydrogen projects in strategic locations alongside customers’ plants, like at ArcelorMittal SA’s steel mill in the German port of Hamburg, where it can also add hydrogen refueling for trucks.

The industry is also getting government support. The European Union paid half the roughly $23 million cost of Shell’s Rhineland project and has earmarked funding for hydrogen as part of its pandemic recovery program.

In the U.S., the Energy Department has said it aims to reduce the cost of green hydrogen by 80% to $1 per kilogram in the next decade, in part by supporting pilot projects.

Consultants and oil company executives say an interim step to reaching large-scale green hydrogen production is to capture and store carbon generated by making hydrogen from natural gas to reduce emissions—making what is known as blue hydrogen.

Critics of fossil-fuel hydrogen where carbon is captured say the process is expensive, and that extracting and transporting natural gas often results in greenhouse gas leaks, meaning any hydrogen produced likely won’t be zero-carbon.

Oil-and-gas companies want to pursue this approach because it “could extend the life of their fossil assets,” said Cameron Hepburn, director of the Smith School of Enterprise and Environment at the University of Oxford.

Some U.S. oil companies also are pursuing hydrogen.

Chevron Corp. has signaled that it sees hydrogen having a role in transportation, as an industrial feedstock and in energy storage. This month, it partnered with engine maker Cummins Inc. to explore hydrogen infrastructure and fuel-cell vehicles, following a similar agreement in April with car maker Toyota Motor North America Inc.

Amid the enthusiasm, there needs to be greater focus on where best to deploy green hydrogen, said Michael Liebreich, chief executive of consulting firm Liebreich Associates.

The priority should be to replace gas-based hydrogen for tasks like making fertilizer and in hard-to-abate industries such as steel, aviation and shipping, Mr. Liebreich said, adding that it makes less sense where electricity could be used directly, like in domestic heating, cars and trains.

One area where there is an active debate around the merits of switching to hydrogen is long-distance trucking.

In recent months, Volkswagen AG’s Scania brand has scaled back its hydrogen research to focus on batteries instead, saying hydrogen trucks require three times as much electricity, while Daimler Truck AG and Shell agreed to jointly push the adoption of hydrogen fuel-cell trucks in Europe, pledging to roll out 150 refueling stations.

Tom Baxter, a visiting professor in chemical engineering at Scotland’s University of Strathclyde, said it is too early to judge what role hydrogen could play in areas such as aviation and shipping, and that he is skeptical about some of the other new uses being touted.

“For big trucks going across the [U.S.] or Australia hydrogen might have a role, but it’s niche,” Mr. Baxter said. “Setting hydrogen alongside the alternatives that we have, particularly electrification, it’s there that the hydrogen story starts to unravel.”

Updated: 8-8-2021

Kuwait Posts Record $36 Billion Deficit On Oil Price Drop, Virus

Kuwait’s budget deficit swelled to a record in the year through March as oil prices plunged and the coronavirus pandemic negatively impacted the economy.

The gap climbed 175% to 10.8 billion dinars ($36 billion) in the last fiscal year, compared with a year earlier, the Finance Ministry said in a statement on Saturday.

The OPEC member has been battling to reduce its deficit due to its dependence on oil revenues, and high spending on civil servant wages and subsidies. Ongoing political squabbles have prevented the government from passing laws to allow it to borrow and withdraw as much as 5 billion dinars a year from the Future Generations Fund — a $700 billion savings pot designed for life after oil. The country hasn’t been to the market since a debut Eurobond in 2017.

Lawmakers have said the government should better manage its finances and fight corruption before resorting to debt.

Last month Kuwait was downgraded by S&P Global Ratings for a second time in less than two years. The rating agency said the downgrade reflects “the persistent lack of a comprehensive funding strategy despite the central government’s ongoing sizable deficits.”

Kuwait’s government projects a cumulative budget deficit of 55.4 billion dinars in the five fiscal years ending March 31, 2025.

Updated: 8-13-2021

First New Oil Sands Pipeline In Years Could Start Next Month

A key pipeline linking Canada’s oil sands crude to U.S. markets could start shipping crude as early as next month.

Enbridge Inc.’s 760,0000 barrel-a-day Line 3 oil pipeline could start operating as soon as Sept. 15, bringing relief to Canadian oil sands producers who have had with limited access to export pipelines. The new Line 3 pipeline from Alberta to Wisconsin replaces an older line with less capacity, is as little as 30 to 60 days from completion, according to a notice sent to shippers.

Canada’s oil sands producers have struggled for years with a shortage of export conduits as projects to build new ones face increasing scrutiny from courts and regulators. U.S. President Joe Biden, on his first day in office, rescinded a permit for TC Energy Corp.’s Keystone XL pipeline that would have helped increase shipments of Canadian crude to the U.S. Gulf Coast.

“Enbridge has filed for a toll surcharges on the Line 3 replacement with the Canada Energy Regulator and Federal Energy Regulatory Commission, which could be effective as early as Sept. 15,” spokesperson Jesse Semko said in an emailed statement. “There will be a further filing to specify the specific in-service date shortly before the line goes into service once all necessary construction and commissioning activities are complete.”

Heavy Western Canadian Select crude for September delivery strengthened 20 cents to a $12.80 a barrel discount to benchmark West Texas Intermediate at 9:37 a.m. Calgary time, NE2 Group data show.

The pipeline would be the first new cross-border export project built between Canada and the U.S. in years. The line is scheduled to enter service with oil sands production exceeding the capacity of existing lines out of Western Canada, forcing some companies to ship crude by rail.

The Line 3 project has been fiercely opposed by some environmental and indigenous groups, who have staged protests this summer along the construction route. Enbridge spent years in court fights and regulatory battles to get the line built. The Trans Mountain expansion, another export pipeline under construction is British Columbia, is scheduled to enter service as early as 2022.

Enbridge shares rose 13 cents to $39.32 at 12:35 p.m. in New York.

Updated: 8-14-2021

Oil Giants Turn To Startups For Low-Carbon Energy Ideas

BP, Shell bolster their venture capital arms as they seek to reduce dependence on fossil fuels.

Some of the world’s biggest oil companies are turning to startups to help plot their future.

Energy giants including BP PLC and Royal Dutch Shell PLC are bolstering their venture capital arms—increasing budgets, hiring more staff and doing more deals—seeking out new low-carbon technologies to help future-proof their profits.

The moves come as several big oil companies work to reduce their dependence on fossil fuels and expand their low-carbon activities, partly in response to growing pressure from investors and governments to cut emissions.

“They [BP leadership] really want the venture capital activity to help us execute on the new strategy,” said Meghan Sharp, head of BP Ventures.

Venture spending by oil companies represents only a small amount of their multibillion-dollar annual investment budgets. It is also sometimes aimed at boosting oil-and-gas operations, while some clean-tech entrepreneurs can be reluctant to sell to fossil fuel companies.

Nevertheless, BP, Shell, and French peer TotalEnergies SE are now among the most active clean-tech investors by number of deals closed, according to data provider PitchBook, with activity ramping up amid the shift to technologies like electric vehicles and solar and wind power.

Ms. Sharp said BP has put more emphasis on venture capital since setting out plans last year to shrink its oil and gas production by 40% by 2030, while growing its low-carbon business.

The company aims to close 10 deals next year, up from five to seven deals this year, and three in 2019, Ms. Sharp said. BP now expects to spend up to $200 million a year, double what it has spent in some previous years, she added.

BP’s investments this year have included geothermal startup Eavor Technologies Inc.—where it was part of a $40 million funding round alongside Chevron Corp. —and autonomous vehicle software company Oxbotica Ltd.

Ms. Sharp said BP seeks investments that can help achieve its broader goals. For instance, in 2018 it invested in electric vehicle charging company FreeWire Technologies Inc. and last year started deploying FreeWire’s chargers as part of its drive to install 70,000 charging points by 2030.

Shell declined to disclose its venture capital budget but said the number of annual investments it makes had doubled since 2017 to around 20 to 25 deals a year, typically between $2 million and $5 million in size. Over the same period its venture team has expanded to 35 people in seven locations, from 10 people in three locations. Overall it is invested in around 90 companies.

In recent years, Shell Ventures’ focus has shifted from oil and gas to areas including hydrogen, renewable power and future transport solutions, said Geert van de Wouw, the unit’s managing director. One example is Ample Inc., a battery swapping company.

That shift has made the unit, once an obscure part of Shell that lacked some appeal to recruits, a more attractive prospect, particularly to younger staffers.

“Nobody wanted to work for us, we were this strange group of people who interacted with startups and I struggled to find good people,” said Mr. van de Wouw. “There’s no challenge whatsoever anymore.”

This year Shell’s investments included a charging technology, hydrogen-electric planes, and a logistics company that aims to prevent trucks running without goods—all of which could ultimately reduce demand for oil.

Some U.S. oil companies have also sought to boost venture investments. In February, Chevron committed $300 million to a fund focused on low-carbon energy.

Oil companies face various challenges in their pursuit of the next big thing in energy, not least competition. So far this year, there have been 1,177 venture capital deals globally in the sector, worth $89.4 billion, according to PitchBook. That is up from $56.9 billion of deals in all of 2020.

To better compete with typically more agile traditional venture funds, oil executives say they are working to make decisions faster, and highlighting to startups how they could be big customers.

For some startups, the prospect of an oil company becoming an investor, also poses a dilemma.

Chris Kemper, founder of Palmetto Clean Technology Inc., a software company with an app that allows homeowners with solar panels to track their energy consumption, said he managed through some pushback from employees before agreeing to allow Shell to invest last year.

Mr. Kemper, who previously worked on climate issues at the United Nations, said Palmetto team members asked him questions like, “Are we not worried about taking money from a fossil fuel company that in part majorly contributed to the very cause we’re trying to solve?”

Mr. Kemper said he agreed to the deal after being reassured by Shell staffers about the company’s future plans.

Executives say there is often a yearslong wait for startups to turn a profit, and many fail. Shell, like its peers, declined to disclose figures, though Mr. van de Wouw said a failure rate of 60% to 70% “was not unusual.”

Updated: 8-19-2021

Alaska Oil Permits Blocked by Federal Judge

The ConocoPhillips Willow project’s impact on climate change and polar bears wasn’t fully accounted for, judge says.

A federal judge on Wednesday threw out federal approval of a multibillion-dollar oil project planned for Alaska, saying the government failed to properly assess the project’s impact on climate change and its potential harm to polar bears.

The ConocoPhillips Willow project in a federal oil reserve in the North Slope had been backed by both the Biden and Trump administrations, and comes with wide support from Alaskan political leaders. Republican Gov. Mike Dunleavy criticized the decision Wednesday night, saying it put thousands of potential jobs at risk.

U.S. District Judge Sharon Gleason agreed with challengers who argued that the Bureau of Land Management didn’t fully account for the greenhouse gases that would come from burning the oil Willow would produce, among other issues. The plaintiffs, led by the Center for Biological Diversity, included several environmental and Alaskan groups.

“As to the errors found by the Court, they are serious,” Judge Gleason, an Obama appointee seated in Anchorage, wrote in her 110-page decision.

ConocoPhillips will be reviewing the decision and evaluating its options, a spokesman said. The company declined to answer further questions.

Company leaders had been encouraged this spring when the Biden administration decided to defend the Trump-era decision to permit the project. But Conoco’s final investment was always dependent upon whether the company could navigate tricky and potentially lengthy court challenges at a time when oil markets aren’t particularly friendly to major spending in Alaska.

Willow is planned as a 160,000-barrel-of-oil-a-day, 30-year project, drilling from on top of permafrost in the federal government’s National Petroleum Reserve in Alaska.

The Trump administration gave it final approval in October, but the Ninth U.S. Circuit Court of Appeals halted the project this year, siding with challengers who said Willow was approved without proper analysis of environmental impacts.

Judge Gleason Wednesday again ruled that the Bureau of Land Management hadn’t given the full consideration to alternatives to Conoco’s plans that the law requires.

The governor, Mr. Dunleavy, accused the courts of intentionally making challenges to Alaskan drilling even bigger. He said Wednesday’s ruling could make the country more dependent on foreign oil.

“Make no mistake, today’s ruling from a federal judge trying to shelve a major oil project on American soil does one thing: outsources,” Mr. Dunleavy said in a statement. “This is a horrible decision.”

The Biden administration had supported the Trump administration’s analysis in court, which pleased important lawmakers from Alaska and several Western states. But the move had also drawn opposition from environmental groups, some of which said on Wednesday that they were hoping the new decision would lead the administration to reconsider its stance.

“We are hopeful that the administration won’t give the fossil fuel industry another chance to carve up this irreplaceable Arctic landscape with drilling rigs, roads, and pipelines,” said Jeremy Lieb,” an attorney with Earthjustice, which brought the case on behalf of the Center for Biological Diversity and other plaintiffs.

“We should keep Arctic oil in the ground if we want a livable planet for future generations,” he said.

Updated: 9-30-2021

U.S. Frackers Fear Vaccine Mandate Will Worsen Worker Crunch

Oil executives say many workers in shale regions remain unvaccinated, hurting their ability to rebuild workforces as energy prices rise.

American frackers, already struggling to hire enough workers, are concerned that the coming U.S. vaccine mandate will worsen the situation at a time of rising oil and gas prices.

Many of the truckers, rig hands and roustabouts who used to work in Texas and other oil patch regions found other jobs after crude prices crashed last year during the onset of the pandemic.

Oil-field service companies, which employ most of the ground-level workers who drill and finish wells, say many remaining employees are skeptical about Covid-19 vaccination, and some have warned they would quit before getting shots.

The proposed mandate doesn’t require companies to terminate employees who don’t comply, but those workers would be subject to frequent testing. Some companies are concerned that such testing would frustrate unvaccinated employees and motivate them to leave their jobs.

Ann Fox, chief executive of Nine Energy Service Inc., an oil-field service company active across the U.S., said she is worried that it could lose a portion of its workforce of 818, most of which are field-level employees. The company is already dealing with rapid turnover—roughly two out of every three recent new hires tend to leave after a short period, she said.

“It places all of us in leadership positions in tremendously complex situations,” Ms. Fox said, estimating that less than 15% of the company’s field-level workers are vaccinated. Nationwide, 65% of eligible people are fully vaccinated, according to the Centers for Disease Control and Prevention.

Ms. Fox said many in the industry were also concerned about requirements for weekly testing for unvaccinated workers, saying it could be burdensome to administer and manage, with so many small crews working in rural areas.

For now, companies are awaiting guidance on how President Biden’s plan to require Covid-19 vaccines or weekly testing for all employers with 100 or more workers will be implemented. Mr. Biden directed the Occupational Safety and Health Administration, or OSHA, to impose such a mandate earlier this month.

Many companies have welcomed the federal mandate, seeing it as a way to speed up the pace of vaccination and prevent a recent wave of U.S. cases from hampering their workforces and hamstringing the economy. The issue has split the business community, with some employers, especially smaller ones, expressing concern that it will be difficult for them to implement.

But many oil-field service companies are already anticipating problems, based on vaccination rates in the areas where they operate and feedback from their workers.

In Midland County, Texas, the heart of the Permian basin, the most active U.S. oil field, about 46% of eligible people have been fully vaccinated, according to the Texas Department of State Health Services, compared with the state’s overall rate of 61.5%. The region is seeing a plateau in Covid-19 hospitalizations after a monthslong rise that pushed hospitals to near their limits, local health officials said.

Clint Concord, senior operations manager at Byrd Oilfield Services LLC in Odessa, Texas, said many in the oil patch are skeptical of the safety and efficacy of Covid-19 vaccines—including himself. He said he would need to weigh his own options, but that frequent testing for unvaccinated workers might lead him to quit.

“It’s our constitutional right not to put something in our body if we don’t want to,” Mr. Concord said. “They haven’t proven to me this is 100% stable.”

The Food and Drug Administration has said that the vaccines it has authorized in the U.S. have been demonstrated to be safe and effective.

Only a handful of oil-field crew workers at Smith Laydown & Casing Services LLC in West Texas are vaccinated, said Justin Clark, a field-service manager there. Mr. Clark said he has considered getting the shots, and that the latest wave of Covid-19 cases has been eye-opening.

But he said he understood why many in the oil patch would resist mandated vaccinations, or have avoided getting tested.

“I don’t like to be forced to do anything,” said Mr. Clark, 42. “I almost want to just do the opposite when someone tells me, in that manner, you’ve got to do this.”

Executives say vaccination mandates may force companies to raise wages to attract workers, increasing production costs when oil and gas prices are already at multiyear highs because of thinning supplies. Europe is facing an energy crisis due to shortages of natural gas that has led to factory closures in the U.K., and China is dealing with power shortages that have begun to affect production of semiconductors and other key goods.

Payroll represents more than half of oil-field services companies’ costs, making retention and staffing their biggest challenge, according to consulting firm Rystad Energy. The costs of some services including trucking have risen 25% to 35% compared with the fourth quarter of 2020, while daily rates for drilling rigs could climb as much as 15% next year, the firm said.

“It’s going to drive the price of drilling these wells way back up again, just like the grocery store seeing sticker shock,” said Kirk Edwards, president of oil producer Latigo Petroleum LLC.

A survey by the Federal Reserve Bank of Dallas released Wednesday showed about 57% of oil-field service companies reported higher wages and benefits in the third quarter.

About 51% of surveyed oil-field service executives said their companies have had difficulty hiring workers, with more than two-thirds citing a low number of qualified workers and 39% saying that potential hires wanted higher pay than they had offered.

“Wages are up 20%,” one executive who responded to the survey said. “We are finding it difficult to increase prices to match our increase in costs.”

The oil-field worker shortage reflects intense competition for labor across the economy. For example, oil-field truck drivers have found companies like Walmart Inc. and Amazon.com Inc. are willing to shell out wages that match the hefty pay of the oil patch, while others are now working in construction, executives and managers said.

Demand is high for truckers to haul water, sand and other fracking supplies across the Permian basin, which straddles West Texas and New Mexico, but the lack of drivers has forced GM Oilfield & Trucking Services LLC in Midland to turn down jobs every day, said Abel Ortega, a 52-year-old operations manager there.

West Texas trucking companies like Mr. Ortega’s often offer drivers $1,000 to $2,500 sign-on bonuses, benefits and housing, and drivers working 70 to 80 hours a week can make $120,000 to $130,000 a year.

The firm is trying to find enough drivers to double its head count to more than 100, but that growth could be hampered by government requirements to vaccinate workers, and weekly tests could get expensive, he said.

“It’s going to be an obstacle either way,” Mr. Ortega said, adding that some truck drivers would probably quit.

Updated: 10-4-2021

Shell Makes First U.K. Solar Investments Amid Power Expansion

Royal Dutch Shell Plc will make investments with two firms to develop its first solar-power projects in the U.K.

The oil and gas giant signed agreements with Island Green Power Ltd. to develop a project with more than 700 megawatts of generation capacity, and another with Clearstone Energy Ltd. for projects with a combined export capacity of 100 megawatts. Both will be subject to final investment decisions.

Shell, like its European Big Oil peers, has committed to scaling back its traditional oil and gas business in favor of cleaner sources of energy, with electricity as a cornerstone of its transition strategy.

Unlike its competitors, Shell has mostly focused on long-term power purchase agreements or making smaller investments in technology companies. That compares with billion-dollar investments by the likes of BP Plc in wind power or TotalEnergies SE’s acquistion of a stake in Indian renewables firm Adani Green Energy Ltd.

Shell does already own a power provider in the U.K., after its 2018 acquisition of First Utility Ltd. Shell Energy, as the rebranded company is now called, is expanding, having taken on Green Supplier Ltd.’s customers after it collapsed last month.

Updated: 10-6-2021

U.S. Shale Producers To See Minimal Expansion Despite Oil Rally

U.S. shale oil production will expand at a “modest rate” over the next 18 months even as prices touch multiyear highs, according to BloombergNEF, leaving OPEC in a powerful position as the world cries out for more barrels.

Producers are using cash flow to pay down debt and reward shareholders rather than invest in new drilling, BNEF said in a report published Wednesday. Yet demand for energy is rising around the world. U.S. crude futures reached a seven-year high this week after OPEC and its allies declined to alter their supply agreement to raise output.

West Texas Intermediate crude dropped 1.7% to $77.61 a barrel at 11:01 a.m. in New York. Prices have risen 60% this year.

U.S. production will reach 12.1 million barrels by the end of next year, up 440,000 barrels a day from the end of 2021, according to BNEF’s base case scenario. That’s lower than its pre-pandemic record high of 13 million from 2019. Under a bull scenario, in which prices average $80 a barrel from now until the end of 2022, BNEF sees production rising to 12.4 million barrels a day.

The sole driver of next year’s growth will be the Permian Basin of West Texas and New Mexico, with all other regions flatlining or declining.

“U.S. oil producers remain reluctant to increase production meaningfully,” BNEF analyst Tai Liu said in the report.

Updated: 1-2-2022

Libya Shuts Down Another 200,000 Barrels A Day of Oil Production

* Nation Cuts Output At Eastern Fields To Fix Broken Pipeline
* Outages In Libya May Counter OPEC+ Efforts To Raise Production

Libya expects its oil production to drop by another 200,000 barrels a day over the next week as workers try to fix a damaged pipeline.

The latest outage comes less than two weeks after militias shut down the OPEC member’s biggest field, Sharara, causing output to fall by around 350,000 barrels a day. Together, the closures will reduce Libyan production to about 700,000 barrels a day, the lowest in more than a year.

Any sustained drop from Libya, which sits on Africa’s biggest oil reserves, could counter efforts by the Organization of Petroleum Exporting Countries and its partners to boost exports. OPEC+ meets on Tuesday and is likely to proceed with another monthly increase of 400,000 barrels a day, according to a Bloomberg survey, as it restores supplies halted during the coronavirus pandemic.

Libya’s state-owned National Oil Corp. said late Saturday that the main pipeline linking the eastern Samah and Dhuhra fields to the country’s biggest export terminal, Es Sider, will be shut for maintenance. It said the pipe will be working again in a week.

Libya pumped 1.2 million barrels a day on average last year. The NOC has warned it lacks the funds needed to sustain that level of production, let alone reach its target of 2 million barrels per day within six years.

The government is trying to attract billions of dollars of investment from foreign energy companies, including France’s TotalEnergies SE and Italy’s Eni SpA.

Oil facilities can no longer be properly run because of “the large number of leaks” and “the consequences of illegal closures in the past years,” the NOC said in a statement. It also blamed lawmakers for failing to sign off on a budget for the company for the past two years.

Fighting between rival factions in the country, which has been at war or in chaos for much of the past decade, has hindered efforts to increase output. Last month, Libya delayed a presidential election meant to end political divisions and help stabilize the energy sector.

Updated: 1-13-2022

One Of The World’s Dirtiest Oil Patches Is Pumping More Than Ever

Multinational producers have exited Canada’s oil sands, but local companies have stepped in; ‘we will continue to see growth’.

Major oil companies, under pressure from investors and environmentalists, are fleeing Canada’s oil sands, the fourth-largest oil reserve in the world and by some measures one of the most environmentally unfriendly. Investment in existing projects has stalled, and banks are refusing to fund new ones.

Nevertheless, oil production there is expected to continue for at least two more decades. Local companies have stepped in to keep working the existing mines and wells. Last year, the oil sands were on track to deliver more oil than ever.

Governments and financial institutions are pushing to wean the world from fossil fuels to address climate change. But demand for energy remains robust. So long as existing oil fields—no matter their carbon footprint—remain profitable, they are likely to remain in production long after big-name multinational companies walk away.

There are still roughly 170 billion barrels of thick, tar-like bitumen under boreal forests in the Canadian province of Alberta, the largest amount outside of Saudi Arabia, Venezuela and Iran. Domestic companies such as Canadian Natural Resources Ltd. , Suncor Energy Inc., Cenovus Energy Inc. and Imperial Oil Ltd , an affiliate of Exxon Mobil Corp. , extracted more crude from those fields in last year’s third quarter than the same period a year earlier.

Politicians and others pushing for a rapid transition to cleaner energy sources face a conundrum. Despite intensifying efforts to transition the global economy away from fossil fuels, alternative energy sources currently come nowhere near meeting present demand. That means companies will continue to pump oil even from carbon-intensive sources.

“We will continue to see growth,” said Alex Pourbaix, chief executive of Calgary-based Cenovus, which doubled its dividend last year. Cenovus increased third-quarter oil sands production by almost 50,000 barrels a day.

Mr. Pourbaix said the world-wide push for renewable energy wouldn’t reduce oil’s importance as a cheap energy source anytime soon. “There’s no technology at all of scale that can replace what oil can do,” he said. “That’s just reality.”

The benchmark West Texas Intermediate oil price in the U.S., which fell to record lows in the spring of 2020, rose above $70 a barrel in June for the first time since 2018.

The sharp rise in prices has prompted even world leaders committed to reducing emissions to call for more production.

President Biden asked the Organization of the Petroleum Exporting Countries last year to boost production, after gasoline prices climbed, and in November he released oil from the U.S.’s strategic reserve in a bid to tame gas costs.

He also supported the construction of a replacement for Line 3, a pipeline operated by Calgary-based Enbridge Inc. that brings crude from the oil sands to the U.S.

Canadian Prime Minister Justin Trudeau is spending more than $12.5 billion to expand the Trans Mountain pipeline, which carries crude from the oil sands to Canada’s west coast.

The expansion, when it is finished sometime in 2023, will triple Trans Mountain’s capacity to almost 900,000 barrels a day, giving companies such as Cenovus and Suncor greater access to growing markets in Asia.

Mr. Trudeau has said that money from Canada’s oil industry will fund its transition to greener energy.

The production increases in Canada’s oil sands are happening despite a yearslong flight of capital from the area. The region, once one of the energy world’s hottest investment destinations, has become a dead zone for foreign investment.

Since 2017, major oil companies such as Royal Dutch Shell PLC, ConocoPhillips and Total SA have announced plans to sell their Canadian assets or have sold them. The reasons cited include greenhouse-gas emissions and unattractive returns. Chevron Corp. Chief Executive Michael Wirth said he was open to selling a stake in the region because it wasn’t a strategic asset for the company.

Some investment funds managed by BlackRock Inc. and Norway’s sovereign-wealth fund have cut oil sands investments from their portfolios. Last year, the Caisse de dépôt et placement du Québec, one of Canada’s largest pension funds, announced it will sell all its holdings of oil company stocks, including its interests in Canadian companies, by the end of 2022.

“The philosophy behind this is to avoid contributing to additional oil supply,” said Charles Emond, chief executive of the fund, in September. The Caisse manages more than $300 billion in assets for public employees in the province of Quebec, about 1% of which is invested in the stock of oil producers. “This is a leadership decision in the face of the climate crisis.”

As international energy companies have moved out of the oil sands, though, smaller independents and private investors have come in, and some have moved to increase production.

Adam Waterous, chief executive of the Waterous Energy Fund, a Calgary-based private-equity firm, said the firm has bought three oil sands projects in Alberta over the past two years.

Together, the projects produce between 50,000 and 60,000 barrels per day, a number he said could increase to 100,000 barrels a day within the next five years. As a private investor, he said, his company has more freedom to increase production, while investing in technologies to reduce carbon emissions, because it doesn’t have to answer to public shareholders.

Canada’s petroleum industry accounts for roughly 5% of the nation’s economic output. For all but two of the years since 2008, oil has been Canada’s top trade export.

An 88,000-square-mile area in northeast Alberta, the oil sands boomed between 2000 and 2014. Global companies, lured to the region by high oil prices and plentiful supply, raced to Alberta to build extraction megaprojects with names like Sunrise, Peace River and Surmont.

During the boom years, investment in the oil sands totaled $183 billion. Capital spending rose steadily, from $3.3 billion at the beginning of the century to $26.4 billion at its peak in 2014, according to the Alberta Energy Regulator, the provincial department that regulates Alberta’s energy industry.

Alberta’s crude is buried under quartz sand and is difficult to extract. Producers either claw the oil-infused sand out of the ground using excavators that look like dinosaurs, or pump the crude out of wells by injecting steam deep into the earth to liquefy it.

The oil requires a lot of energy to extract and visibly scars the landscape. The mining process creates a slurry of quartz sand, water and toxic chemicals, which is kept in huge reservoirs called tailings ponds that are so big they can be seen from outer space. At the oil wells, thick plumes of steam billow overhead from the millions of gallons of water heated by natural-gas facilities.

According to research firm Rystad Energy, oil sands production in Alberta generates roughly 160 pounds of carbon per barrel, a higher greenhouse-gas emission than any other oil in the world. The firm described the level as “staggering.” U.S. shale oil producers, by comparison, generate an average of 26 pounds per barrel.

Environmentalists began to target the region around 2002, when officials in Alberta first quantified the size of its reserves. “They are arguably the most visible human scars on the planet,” said Bill McKibben, a prominent environmentalist and co-founder of 350.org, a group dedicated to stopping the use of fossil fuels world-wide.

Actor Leonardo DiCaprio visited the oil sands in 2014 and produced a National Geographic documentary on climate change that singled out the region.

Groups such as 350.org, Rainforest Action Network and Sierra Club organized protests in Washington, disrupted pipeline construction projects and pressured banks and financial institutions to pull funding for oil sand projects.

A drop in the price of oil in 2014, coupled with pressure from shareholders of energy company to reduce emissions, affected investment. In 2020, capital spending on oil sands projects hit a 16-year low, totaling $5.8 billion, according to the Alberta Energy Regulator. Such capital investment has declined every year since it peaked in 2014. It was forecast to have risen slightly in 2021, but remain lower than it was in 2019.

In 2017, when Shell announced the sale of several oil sands assets for $7.25 billion, Chief Executive Ben van Beurden said that the company wanted to boost returns. The announcement came at the same time the company said it was linking director bonuses to greenhouse-gas emission reductions.

In June 2021, Calgary-based pipeline operator TC Energy Corp. announced it was ending a 12-year effort to build the Keystone XL pipeline extension, a conduit for Canada to get its oil to the U.S. market. The announcement came six months after Mr. Biden kept a campaign promise by canceling the permit that had allowed the pipeline’s construction to move forward.

Almost 60 financial institutions, including Deutsche Bank, HSBC Holdings PLC and insurance company Hartford Financial Services Group Inc., have curbed their oil sands investments. In July, Japan Petroleum Exploration Co. , Japan’s state-backed oil-and-gas company known as Japex, which first leased land in Alberta in 1978, announced it sold its stake in the Hangingstone oil sands project at a loss of $800 million.

Employment in Canada’s oil-and-gas industry declined by 17% between 2014 and 2019, from 226,500 to 188,760 in 2019, according to Petroleum Labour Market Information, a division of the Energy Safety Canada, an organization that works with companies and workers to set industry safety standards.

The nonprofit estimated that Covid-19-related layoffs accelerated the downward trend, and that the industry shed another 20,000 jobs in 2020.

The toll is visible in Calgary, the corporate hub of Canada’s energy industry. The steel and glass skyscrapers that tower over the prairie landscape on the shores of the Bow River were built during the industry’s heyday. Today, many are nearly empty.

Downtown Calgary had a commercial real-estate vacancy rate of 33% in the third quarter of 2021, the highest in North America, according to CBRE Group, a commercial-real-estate services firm. Houston’s vacancy rate, by comparison, was 24%.

Eventually, the lack of investment will cause production to dwindle as oil from some projects is depleted, analysts say. Some projects could start to deplete by the middle of the next decade, according to Kevin Birn, an analyst with IHS Markit.

Some mines are being modified as the original reserves run low. The North Mine at the Syncrude project, which is operated by Suncor, is expected to be depleted by the middle of this decade, but an extension of the mine is being built that will keep it producing for another 14 years.

Newer projects, though, are likely to produce far into the future. Fort Hills, an open pit truck and shovel mine run by Suncor, completed in 2018, can produce almost 200,000 barrels of oil a day. It can run for the next 50 years, based on current plans.

In October, producers extracted more than 3.84 million barrels a day from Alberta, a record, according to the Alberta Energy Regulator. Between January and October, production totaled 1.09 billion barrels, also a record.

Updated: 1-17-2022

Frackers In America’s Hottest Oil Field Are Facing An Expensive New Setback: Earthquakes.

Shale companies in West Texas will have to pay more to move millions of barrels of wastewater that surfaces from oil wells and can aggravate tectonic fault lines when deposited underground. A recent spate of earthquakes prompted state regulators to stop companies from pumping as much water underground, forcing some drillers to move water farther afield.

Most of the earthquakes have been relatively mild so far and have caused limited property damage. The rising number of earthquakes has led the Texas Railroad Commission, which regulates the oil industry, to shut or sharply reduce the capacity of scores of so-called disposal wells to protect nearby communities.

The wells are used by large oil companies including Chevron Corp., ConocoPhillips and Coterra Energy Inc. to inject wastewater into geologic formations. The limitations have left Permian Basin drillers to find other ways to transport wastewater, including high-cost trucking.

Trucking the water to disposal wells elsewhere is about five times the cost of using pipelines, according to shale executives and analysts. Some companies said they can avoid trucking by sending water through a network of pipelines to regions unaffected by seismic activity. The added expenses come as frackers are already facing higher costs from labor and supplies.

Permian producers’ collective annual cost to jettison that water could increase, conservatively, by more than $200 million if they have to truck it all out, according to market intelligence firm Sourcenergy. If companies are unable to find new means of disposal, they may have to curtail tens of thousands of barrels a day of oil production.

The setback could also limit some producers’ ability to increase output in response to the highest oil prices in years. Many that are forced to truck water elsewhere will likely have to shift drilling rigs away from the areas where the Railroad Commission concentrated its cutbacks, executives said.

“If you’re forced to truck it, it’s going to have a devastating impact on your lease operating expenses,” said Richard Jennings, president of private West Texas oil producer Atlantic Operating II LLC, which says it operates shallow disposal wells unaffected by the restrictions.

In 2020, the latest year for which data is available, oil producers pumped about 342 million barrels of water into the saltwater disposal wells that the Railroad Commission began restricting last fall. The regulator acted after a sharp uptick in earthquakes, including near populated areas like Midland and Odessa.

The number of earthquakes with a magnitude of 3.0 or larger in the Texas portion of the Permian rose to 176 last year, up from 51 in 2020 and nine in 2019, according to Sourcenergy, which analyzed state seismic activity data.

U.S. seismologists have linked seismic activity to wastewater disposal in oil fields. In Oklahoma a few years ago, regulators moved to limit injections in some areas following a rise in earthquakes that damaged buildings and caused injuries.

The large volumes of injected water can increase pore pressure in certain geologic formations, and if faults run through those formations, the pressure pushing against them can cause seismic events, scientists say.

The Railroad Commission in September curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa, and has since suspended some permits there and expanded the restrictions to other areas. It has said the suspensions are in effect until further notice.

The water that companies injected in 2020 into now-restricted wells would have exceeded the new limits by about 104 million barrels, according to Sourcenergy. It said the amount of water companies injected in those wells in 2021 was likely much higher as drillers brought new wells online.

If Chevron had to truck all of its excess water in 2020, it would have raised costs by $53 million a year, Sourcenergy estimates. For Coterra, the company formed by the combination of Cimarex Energy Inc. and Cabot Oil & Gas Corp., trucking all its excess water would have raised costs by $63.5 million.

Some companies said they could avoid trucking water by recycling it, pumping it through extensive pipeline networks or other means.

Coterra said it is working to increase options for wastewater, including recycling and reusing it, and creating new disposal wells. Chevron spokeswoman Deena McMullen said the company has options to move water elsewhere through its existing pipelines or agreements with other companies to use their pipeline space and it is reviewing other alternatives to trucks.

Even so, there are questions about how far pipelines can carry the excess water, and whether those systems have the capacity to absorb the disrupted flow, analysts said.

“You just can’t truck a significant volume of water and make any money. It eats up all your revenue,” said Jim Wilkes, president of private oil producer Texland Petroleum LP.

Permian oil wells can produce anywhere from 1,000 to 5,000 barrels of water a day. Trucking that water away isn’t a sustainable option for any company, executives said, as it costs about $2.50 a barrel, compared with about 50 cents a barrel on a pipeline.

Executives said they expect the Railroad Commission will expand its restrictions to other areas hit by numerous earthquakes.

For oil producers, costs have already jumped higher, driven by supply-chain shortfalls, the rising cost of steel and a constrained labor pool. The Federal Reserve Bank of Dallas’s fourth-quarter survey of oil executives showed record-high readings for indexes of oil-field costs, in data going back five years.

About 60% of oil-field service companies in the survey said they expected their prices would rise 10% or more this year.

“Our costs are going out of sight,” said Gary Bolen, owner of private West Texas producer Pharaoh Oil & Gas Inc. “It seems like you’re making some money, but you start getting kicked in the face in some other ways.”

Updated: 1-20-2022

LNG Boom Helps Orders Soar At World’s No. 2 Oil Contractor

* Baker Hughes Boosted Global Orders 28% From A Year Earlier
* Rig Counts Fell To Record Low As Crude Consumption Plunged

Oil and gas drilling is big business once again, if the leap in demand for services from Baker Hughes Co., the world’s No. 2 oilfield contractor, is any gauge.

The Houston-based company posted equipment orders in its fourth-quarter results that were $1 billion above expectations. That led to a 28% jump in demand after years of painful cost-cutting.

Shares soared as much as 7.3% to $6.05, the highest in almost three years. The company’s top competitors, Schlumberger and Halliburton Co., are also expected to deliver strong quarterly results when they report over the next several days, in the latest sign that the global oil industry is recovering from pandemic lows.

A “broader macro recovery will translate into rising energy demand in 2022, with oil demand likely recovering to prepandemic levels by the end of the year,” Chief Executive Officer Lorenzo Simonelli told analysts and investors Thursday on a conference call.

Baker Hughes’ bigger order book was led by its turbomachinery business, which makes turbines used by liquefied natural gas producers. Shipments of the fossil fuel are providing a key outlet for shale producers as the U.S. gets set to become the world’s top exporter of LNG on an annual basis, beating out cornerstone suppliers Qatar and Australia.

In U.S. shale, closely-held explorers are expected to remain more active this year as compared to the disciplined spending from their public-company counterparts, Simonelli said on the call. International oilfield growth will be led by Latin America and the Middle East, he said.

“The economic recovery coupled with several years of oilfield underspending has given rise to a new energy cycle,” Charles Minervino, an analyst at Susquehanna International Group, wrote in a note to investors last week. “The diversified services companies should exit 2021 on a high note.”

Global oil drilling is recovering after rig counts plummeted to record lows in late 2020. Explorers around the globe are expected to almost triple the pace of spending hikes this year compared to 2021, according to Evercore ISI. International regions are responsible for a record 81% of explorers’ global spending this year, Evercore analyst James West said by phone.

That’s a promising sign for the big three service companies, which now generate most of their sales outside the U.S. and Canada.

Schlumberger, the world’s biggest oil-services provider, is expected to report results Friday, and Halliburton, the top provider of frack work, will release earnings Jan. 24.

Baker Hughes Fourth-Quarter Financial Results Include:

* Orders Of $6.7 Billion For The Final Three Months Of The Year, Up From $5.2 Billion In The Same Period A Year Earlier
* Sales Of $5.5 Billion That Also Beat Analysts’ Expectations
* Fourth-Quarter Earnings, Excluding Certain Items, Were 25 Cents A Share, Missing Analysts’ Estimates By 2 Cents

Updated: 1-25-2022

UAE’s Top Oil Producer Prepares To Sell Bonds For First Time

* Adnoc Gets S&P AA Rating For New Debt Capital Markets Vehicle
* Entity Known As Adnoc Murban Hires Banks For Debt Meetings

The largest oil producer in the United Arab Emirates is preparing to sell its first bonds as the energy-rich country pushes plans to diversify its economy and attract international investors.

Abu Dhabi National Oil Co. is creating a new entity to become its primary vehicle for selling debt, the company said in a statement. Adnoc Murban, as the issuer will be known, was assigned the third-highest credit rating by Standard & Poor’s and Moody’s Investors Service.

Adnoc will grant the new entity long-term supply rights to its main crude oil grade, known as Murban, according to S&P and Moody’s. Adnoc Murban will then sell the roughly 1 million barrels a day of crude back to the parent company or its trading unit, generating cash to support debt payments, the rating companies said.

Income from the sales will give Adnoc Murban annual cash flow of more than $21 billion based on an oil price between $50 and $70 a barrel, Moody’s said. Oil has gained more than 10% this year and last week traded near $90 a barrel, the highest levels since 2014 as demand recovers after dropping during coronavirus-linked lockdowns.

The UAE, the third-largest producer in the Organization of Petroleum Exporting Countries, is leaning on its oil earnings to help build industries like manufacturing and technology. That’s meant to create jobs and develop sustainable sources of income to support the country when energy demand switches away from hydrocarbons.

Adnoc, whose borrowings have so far been limited to bank loans, has been leading the push to attract foreign investors by selling stakes in some of its businesses to partners and listing units on the stock exchange.

Tapping the bond market will give the company another tool for raising cash and potentially more flexibility to extend its debt maturities. The Abu Dhabi government in 2020 sold a 50-year bond, the longest maturity of any Gulf government debt.

Funding Opportunities

Adnoc said the new entity “intends to closely monitor market conditions and explore potential funding opportunities.” Adnoc Murban will conduct introductory meetings with fixed-income investors starting Tuesday ahead of an expected debt sale this year, according to a mandate. JPMorgan Chase & Co. and Morgan Stanley are coordinating the meetings.

Murban crude, pumped from onshore deposits in Abu Dhabi, makes up roughly half of Adnoc’s overall production capacity of 4 million barrels a day. The rest comes from fields in the Persian Gulf. Adnoc has rights to 60% of Murban output with international partners including BP Plc and TotalEnergies SA holding the rest.

Adnoc began trading Murban on an Abu Dhabi-based exchange last year and hopes that other reqional producers will adopt it as a pricing benchmark for their own barrels.

Adnoc Murban received a AA rating with a stable outlook from S&P and an Aa2 rating by Moody’s. Fitch Ratings assigned the entity an AA ranking.

Updated: 1-27-2022

What’s Behind Wall Street’s $100 Oil Forecast?

Dwindling inventories in the developed world, rising demand and doubts about OPEC’s output are supporting predictions for higher crude.

Wall Street’s summer forecast calls for $100 oil.

A barrel hasn’t cost that much since the summer of 2014, before OPEC launched a price war with U.S. shale producers and sent oil prices into a yearslong slump. Early in the pandemic, prices fell to uncharted depths. But the bust ended last year, when crude prices gained more than 50% and oil stocks led the broader market higher.

The benchmark U.S. barrel has added another 15% to start this year, ending Thursday at $86.61. Brent crude, a key price in international trade, closed at $89.34 a barrel, also up about 15% in 2022. Energy shares in the S&P 500 have risen 19% this year, the only sector in the stock index up through Thursday’s close.

Analysts expect oil demand to return to pre-pandemic levels this year and say that prices need to rise higher yet to entice U.S. producers to drill more wells and to discourage consumption that has been unbowed by the highest gasoline prices in years.

U.S. producers have been rewarded by investors for restraint since flooding the market with shale oil before the bust. Meanwhile, break-even drilling costs are rising because of labor and materials inflation and a shakeout that has reduced capacity and competition for hydraulic fracturing and other oil-field services.

“The oil market is heading for simultaneously low inventories, low spare capacity and still low investment,” Morgan Stanley analysts wrote in a research note, lifting their price forecast for the summer quarter by $10 a barrel, to $100 for Brent and $97.50 for West Texas Intermediate.

Goldman Sachs raised its estimate for the period by $20 a barrel, also to $100 for Brent and slightly less for U.S. crude.

Bank of America predicts that West Texas Intermediate will hit $117 by July and that Brent will reach $120.

The case for $100 oil rests on consumption that is increasingly unconstrained by Covid-19, diminishing stockpiles among industrialized nations and doubt that the Organization of the Petroleum Exporting Countries can increase production as it has promised the market.

In November, when the Omicron variant emerged, oil markets were gripped with fear that another spell of shut-in consumers was afoot. But Omicron did much less to dent fuel demand than earlier waves of Covid-19 infection.

November traffic in the U.S. wound up the highest in a decade, with 12% more miles traveled than a year earlier, when the Delta variant was rampant, and 2.8% more than in November 2019, before the pandemic, the Federal Highway Administration said this week.

As air traffic recovers and still-restricted economies reopen around the world, supplies will be stretched thin, analysts say. Goldman anticipates that by summer the developed world’s oil inventories will have drained to their lowest level in two decades.

OPEC and its cooperators, including Russia, have fallen short in their efforts to increase output to pre-pandemic levels. Angola, Nigeria and Iraq have production problems.

Russia has blamed lower output on delays in developing oil fields. If negotiations with the U.S. fail to de-escalate tension along the Ukrainian border, where Russian troops have amassed, oil shipments from one of the world’s largest producers could be disrupted.

Saudi Arabia, among the few exporters that can quickly increase production, has declined to make up for its market allies’ unmet quotas.

Goldman’s analysts say that the combination of low inventories and spare capacity have historically been resolved by sharp price rallies. The investment bank said market fundamentals are appearing to be comparable to when prices surged during the 1990-91 Gulf War, Libya’s 2011 civil war and three periods in between.

The difference these days is shale. Last decade’s fracking boom proved there are huge domestic reserves that can be tapped quickly by a swarm of producers if the price is right.

Domestic crude production has climbed much of the way back from pandemic lows toward the 13 million barrels a day that were being pumped when the economy was shut down in March 2020. Drilling activity remains shy of pre-pandemic levels, but the 491 rigs pursuing oil in the U.S. last week is up from 289 a year earlier, according to Baker Hughes Co.

With larger energy producers under pressure from investors to stick to their drilling budgets and return excess cash to shareholders, smaller, closely held producers led the rebound in drilling last year. Without the scale, bargaining power and quick-to-pay-off gushers of larger firms, smaller producers bear the brunt of rising costs for oil-field services and are unlikely to repeat last year’s production growth spurt, analysts say.

Texland Petroleum LP was among the producers that halted output when prices crashed during the shutdown. The closely held Fort Worth, Texas, company has since brought its roughly 1,200 wells back on line and late last year drilled some more.

Output remains several hundred barrels a day lower than before the pandemic, yet the company doesn’t plan to drill new wells until later this year, given rising oil field costs, such as steel and trucking, said Jim Wilkes, Texland’s president.

“We could drill enough if the economics were right,” he said.

Investors are expecting gangbuster years from the firms that sell services and equipment to oil producers. There is less competition since the oil bust wiped out weaker players and aging equipment was scrapped.

Halliburton Co. HAL -3.45% shares have started the year with a 35% gain, leading the S&P 500. Larger rival Schlumberger NV SLB -3.39% is close behind, up 30%, and followed in the new year’s top 10 performers by eight oil producers. Halliburton said it expects its customers in North America to boost spending by more than 25% this year.

High prices have producers racing to open up wells that have been drilled but not yet completed, and the market for equipment needed to get the oil flowing is already tight, with roughly 90% utilization, Chief Executive Jeff Miller told investors this week.

“Halliburton is sold out,” he said.

Updated: 1-28-2022

Hundred-Dollar Oil May Be Coming Within Months, Chevron CEO Says

* Geopolitics Are Now A Factor, Wirth Says On Bloomberg TV
* Oil Markets Will Rebalance Over The Longer Term, Chief Says

Triple-digit oil prices are possible in the next few months as geopolitical risks and “struggling” supply hit global crude markets, said Chevron Corp.’s top executive.

Demand for petroleum is growing faster than production as the world transitions away from the worst of the pandemic, Chief Executive Officer Mike Wirth said Friday on Bloomberg TV. But in contrast to recent years, international politics, such as Russia’s military build-up near Ukraine, are also starting to spook markets, he said.

“A few years ago these types of events didn’t seem to really impact commodity markets, and today they seem to be doing so,” he said. Oil priced at “$100 is certainly within the realm of what we could see in the next few months.”

Brent crude traded up 1.7% to $90.83 a barrel at 10:58 a.m. in New York, close to a seven-year high.

But sky-high oil prices won’t last indefinitely, Wirth said after the company reported fourth-quarter earnings. “Longer term we think markets rebalance and prices will moderate.”

Updated: 2-3-2022

Oil Frackers Brace For End Of The U.S. Shale Boom

Limited inventory leaves the industry with little choice but to hold back growth, even amid high oil prices.

The end of the boom is in sight for America’s fracking companies.

Less than 3½ years after the shale revolution made the U.S. the world’s largest oil producer, companies in the oil fields of Texas, New Mexico and North Dakota have tapped many of their best wells.

If the largest shale drillers kept their output roughly flat, as they have during the pandemic, many could continue drilling profitable wells for a decade or two, according to a Wall Street Journal review of inventory data and analyses.

If they boosted production 30% a year—the pre-pandemic growth rate in the Permian Basin, the country’s biggest oil field—they would run out of prime drilling locations in just a few years.

Shale companies once drilled rapidly in pursuit of breakneck growth. Now the industry has little choice but to keep running in place. Many are holding back on increasing production, despite the highest oil prices in years and requests from the White House that they drill more.

The limited inventory suggests that the era in which U.S. shale companies could quickly flood the world with oil is receding, and that market power is shifting back to other producers, many overseas. Some investors and energy executives said concerns about inventory likely motivated a recent spate of acquisitions and will lead to more consolidation.

Some companies say concerns about inventories haven’t factored into their decisions to keep output roughly flat. For several years before the pandemic, frustrated investors had pressured companies to slow production growth and return cash to shareholders rather than pump it back into drilling.

Companies have promised to limit spending, though some executives recently said high prices signal a need for them to expand again this year.

U.S. oil production, now at about 11.5 million barrels a day, is still well below its high in early 2020 of about 13 million barrels a day. The Energy Information Administration expects U.S. production to grow about 5.4% through the end of 2022.

Big shale companies already have to drill hundreds of wells each year just to keep production flat. Shale wells produce prodigiously early on, but their production declines rapidly. The Journal reported in 2019 that thousands of shale wells were pumping less oil and gas than companies had forecast. Many have since marked down how many drilling locations they have left.

Some shale companies will eventually have to start spending money to explore for new hot spots, executives and investors said, and even then, those efforts are likely to add only incremental inventory. Few are currently doing so.

Pioneer Natural Resources Co. , the largest oil producer in the Permian Basin of West Texas and New Mexico, raised its oil production between 19% and 27% a year in shale’s peak years. Now, Pioneer is planning to increase output only 5% a year or lower, for the long term.

Scott Sheffield, chief executive of Pioneer, said the combination of investor pressure and limited well inventory means he cannot drill as he once did. “You just can’t keep growing 15% to 20% a year,” he said. “You’ll drill up your inventories. Even the good companies.”

Pioneer bought two smaller drillers last year, Parsley Energy Inc. and DoublePoint Energy, in deals valued at almost $11 billion combined. Mr. Sheffield said that with those acquisitions, his company has about 15 to 20 years left of inventory. Pioneer’s pool of potential drilling locations would last only about eight years at a 15% to 20% growth rate, he said.

While privately held oil producers have increased their output in the Permian this past year, Mr. Sheffield warned even the largest of those would drill through their inventory rapidly if they kept it up.

Mr. Sheffield said he expects U.S. oil production to grow around 2% to 3% a year, even if oil trades from $70 to $100 a barrel. U.S. oil prices settled at $88.26 a barrel Wednesday.

Many drillers say they will never return to pre-pandemic production growth levels of up to 30% a year, in part due to rising costs for raw materials and labor, a lack of available financing and the enormous number of new wells it would require.

Five of the largest shale companies— EOG Resources Inc., Devon Energy Corp. , Diamondback Energy Inc., Continental Resources Inc. and Marathon Oil Corp. —all have about a decade or more of profitable well sites at their current drilling pace, according to the Journal’s review.

They would exhaust that inventory within about six years if they grew output 15% a year, according to analytics firm FLOW Partners LLC, which provided one of the analyses the Journal reviewed.

The Journal examined information about drilling inventories from analytics firm FLOW; Bernstein Research, part of asset-management company AllianceBernstein LP; and energy consulting firm Rystad Energy. While each of the three made different assumptions, they all pointed to similar limits on inventory.

Some companies disputed they are running low on prime wells, arguing that FLOW had inaccurately labeled some of their better wells as uneconomic, among other reasons. Others said technological advances would allow them to extend the life of their acreage.

For years, frackers told investors they had secured enough drilling spots to keep going for decades. In 2018, Continental, which paved the way for a drilling bonanza in North Dakota’s Bakken field, said there could be 65,000 wells drilled there, producing 37 billion barrels of oil.

But to drill all those wells, Rystad said companies will have to explore the region further and improve on existing techniques, and it estimates the region could ultimately yield only as many as 28 billion barrels of oil.

Companies have drilled around 18,500 wells in the Bakken and Three Forks formations in North Dakota and Montana, and though high prices may eventually spur exploration, companies have around 16,500 wells left to drill in their existing acreage using proven drilling methods, with less than 3,200 of those considered top-tier, according to Rystad.

Continental didn’t respond to requests for comment.

Frackers made a big dent in their inventory as many sought to harvest sweet spots to survive lower oil prices during the pandemic. In recent years, they’ve also discovered that their projections for how many wells they could cram into tight spaces were overly optimistic.

Companies learned that newer wells drilled too closely to older ones often caused interference with the original wells’ oil production or caused new wells to perform worse than expected. They eventually spaced wells farther apart, cutting into estimates of how many they had left to drill.

Since the end of 2016, the number of remaining top-tier drilling locations across five major U.S. oil regions has been cut from more than 68,000 to less than 35,000, Rystad estimates.

In the Bakken and the Eagle Ford shale of South Texas, two early fields that sparked the fracking boom, drillers had already significantly slowed their growth before the pandemic. The pre-pandemic number of rigs had fallen about 77% from its all-time peak in the Bakken and around 70% in the Eagle Ford.

Even at reduced paces, producers would sap the Bakken’s top-producing wells in less than six years and the Eagle Ford’s in less than five, the Rystad analysis showed.

Rystad figures include only the most profitable 25% of each region’s remaining inventory. In core areas of the Eagle Ford and Bakken, the most prolific acreage has already been drilled up, Rystad and Bernstein noted.

The Permian is expected to be the longest-lived U.S. oil region and is home to more than 80% of the country’s remaining economic drilling locations, according to Wood Mackenzie. The energy consulting firm projects production growth will plateau there by 2025.

One company exploring new places to drill is EOG, the spinoff once known as Enron Oil and Gas and the fourth-largest U.S. oil company by market capitalization. EOG developed some of the earliest shale techniques, pioneering fracking and horizontal drilling to unlock oil from tight rock formations.

EOG is now one of the few companies trying to find new places to frack for oil and gas within the U.S. under new Chief Executive Ezra Yacob. The 45-year-old, who previously led the company’s exploration division, said EOG’s exploration isn’t motivated by concerns about running out of inventory, but rather is constantly looking to increase returns by scouting out the most lucrative drilling locations.

“The cost of supplies, when you move out of those sweet spots, is going to start going up,” Mr. Yacob said.

EOG last year said it spent roughly $300 million on domestic exploration. It hasn’t disclosed the locations of its domestic exploration wells.

Tom Loughrey, president of FLOW, estimated EOG has about 12½ years left of inventory if it keeps output roughly flat, but only 4.4 years if it boosted output by 15% a year. EOG disagreed with FLOW’s assessment, saying it estimates it has many more economic wells left to drill—about 11,500 so-called premium drilling locations that would last 23 years if it continued at last year’s pace.

“EOG is highly confident in our inventory of future drilling locations,” spokeswoman Kimberly Ehmer said.

Devon had about 9.2 years left at its current pace, according to FLOW. But that would shrink to about 2.2 years at 15%-per-year growth. That’s because once it has drilled its high-return acreage in Permian and Eagle Ford, it would quickly harvest assets in the less productive Powder River Basin of Wyoming and the Stack, in Oklahoma, according to FLOW.

Lisa Adams, a spokeswoman for Devon, said the company’s strategy of moderating growth is motivated by its commitment to a disciplined spending plan that will generate higher returns, not concerns about inventory levels. At its current pace, the company has more than 10 years of inventory, she said.

Some analysts believe companies’ concerns about shrinking sweet spots motivated a recent spate of multibillion-dollar corporate acquisitions and land sales. In early November, Continental said it would pay about $3.3 billion for land in the Permian Basin from Pioneer.

Continental executives at the time said the deal wasn’t motivated by concerns about inventory. FLOW estimates Continental had about 4.5 years of Bakken inventory left at its current pace. After the Permian deal, the company would have about 11 years remaining. Even with the Permian acquisition, the company’s inventory would be exhausted in about three years at 15%-per-year growth, according to FLOW.

The estimate didn’t include assets Continental agreed to purchase from Chesapeake Energy Corp. last month in the Powder River Basin, for about $450 million in cash.

EOG’s Mr. Yacob believes his peers will eventually have to invest in risky exploratory drilling. Of the industry’s top-tier drilling locations, he said, “They’re going pretty fast.”

Updated: 2-4-2022

U.S. Shale Is Back To Booming

Output in the U.S. shale patch is “re-booming” this year, with research and data analysis firm Lium LLC forecasting production will surge by more than 1 million barrels a day.

That’s the most bullish industry forecast yet. By comparison, the Energy Information Administration says the U.S. will end the year producing about 630,000 barrels a day more than January levels; ConocoPhillips predicts output will grow by as much as 900,000 barrels a day in 2022.

The addition of more than 1 million barrels a day would represent the region’s largest expansion of output since 2018, according to Lium.

“Field level datapoints in recent weeks have highlighted a surge in frac activity, which we believe will translate into a production inflection by mid-year,” the firm wrote in a late Thursday research note. “The industry is finding (and we think will continue to find) a way to put plenty of service activity into the field.”

Private operators, which represent more than a third of U.S. output, are expected to “re-boom” over the next six months as they get ready to complete wells, while the major oil companies — accounting for another 18% of production — have already started growing production, Lium said.

Exxon Mobil Corp. said Tuesday it plans to boost output by 25% this year in the Permian Basin, the biggest U.S. oil-producing region. That comes four days after Chevron Corp. announced it will ramp up its own Permian supplies by 10% from an even larger production base.

Updated: 2-5-2022

Jammed In A Cage With No Escape, Women Suffer Mining’s Dark Side

* Companies Brace For New Front Of Investor Pressure On Culture
* Rio Tinto Published Report Detailing Harassment, Racism

 

Noxolo Bobotyane, a veteran of more than a decade in South Africa’s gold fields, has seen first hand how women are sexually harassed as they start their shifts each day. Jammed into a metal cage with other mineworkers as they descend deep below the earth’s surface, there is literally no way out.

“The distance we are standing when we are inside the cage, we are so close to each other,” said Bobotyane, who is a union steward. “A man will touch you, when you are just standing in front of him and there is no way you can go anywhere, you are just standing in front of him. So you just wait for the cage to go down.”

From South Africa’s ultra-deep shafts to the vast iron ore pits of Western Australia, the message from the world’s mines is overwhelming. Women are not safe. Local workers across the board are confronted with blatant and normalized racism, often from their expatriate managers. And a pervasively macho culture in the remote camp sites means that bullying is a normal part of the job.

Mining’s toxic culture is no secret. But an explosive report this week from Rio Tinto Group has laid bare the scale and severity of the problem. The world’s biggest mining companies are already under heavy investor scrutiny for their contribution to global emissions — now the disturbing revelations are threatening to open a major new front of investor pressure.

“Senior leaders and boards across the mining industry should also be carefully considering if they should take similar steps,” said Debby Blakey, chief executive officer at the Health Employees Superannuation Trust Australia, which manages A$68 billion in retirement savings for 900,000 workers, more than 80% of whom are women.

“HESTA will be writing to mining companies to understand how they are considering these issues and will seek to engage with senior management and boards on how they are overseeing company culture,” Blakey said.

Investors this week welcomed Rio Tinto’s transparency in publishing its investigation, but said they will press the company and others on the issue. Several said they are likely to push for similar disclosures from other large producers.

Senior executives at big mining companies said they are expecting that scrutiny over the issue could become comparable to the backlashes over environmental disasters or worker deaths that triggered industrywide changes in the past.

Rio Tinto said earlier this week it will implement all the recommendations in the report, which was conducted for the company by former Australian Sex Discrimination Commissioner Elizabeth Broderick. BHP Group, the largest miner, said in a statement that it has extensive training, systems and processes in place to keep improving both the physical and psychological safety of its employees.

The company also said that in the last two years it had significantly increased its work to address gender-based and domestic violence.

The Rio Tinto investigation found that more than a quarter of female workers had experienced sexual harassment and almost half of all staff have been victims of bullying. A total of 21 women reported actual or attempted rape or sexual assault at company sites over the past five years.

One person said there was an unofficial list of individual leaders that female employees should avoid having early morning or late night meetings with, the report said. Some of those leaders are still working for Rio Tinto, it said.

But the issue goes beyond Rio Tinto.

“Rio Tinto’s report is only shocking to those who haven’t had the experience of working or living in the sector,” said Patricia Procopio, the president of Women in Mining Brasil who has been in mining for over 30 years. “This is the reality for many of us.”

Sexual harassment in the cages — or elevators — has been a problem for years in South Africa, said Hanlie van Vuuren, head of health and safety at union Solidarity.

Two female mine workers — Boitumelo and Mpho, who asked to be referred to by their first names only — also described harassment in cages during Bloomberg interviews this week. Both said female workers are made to feel unwelcome at mines and targeted to provide sexual favors.

The damning revelations come at a crucial time for an industry long associated with being dirty and dangerous. The modern world is utterly dependent on the materials it produces and the energy transition is impossible without it.

But investors are increasingly demanding more from miners on environmental issues like emissions. And Rio itself was forced to confront governance shortfalls two years ago after it destroyed ancient Aboriginal sites in Australia, sparking an investor backlash and eventually replacing its top leadership.

Clearly mining is not alone in having to face up to widespread sexual harassment or racism. But the way the industry operates can be particularly enabling for offenders.

Many sites, including Rio’s iron ore mines in the Pilbara area of Western Australia, are so remote that workers operate on a “fly-in-fly-out” basis – alternating two to four weeks at the mine and then getting a similar amount of time off to go home or on vacation. Workers live in camp-style accommodation that blurs the line between work and social life.

Last year BHP said it had fired 48 workers at its sites in Western Australia since 2019 after verifying allegations of harassment. The cases emerged after Western Australia’s parliament in July announced an inquiry into sexual harassment in mining following a spate of allegations.

The industry also has a long history of racism, often exemplified by white expats — especially from mining hotspots such as South Africa, Australia and Canada — managing indigenous workers. Rio’s report contains accounts of normalized racism, from casual slurs to a lack of progression and promotion.

“Racism happens here every day, every week, and it’s not just one person,” said one account in the report. “It’s continuous, it affects your work, it damages people,” said another.

So far there has been no indication from any of Rio’s major rivals that they plan to follow suit with such detailed external investigations and publish the findings. Rio and the other companies point out that they have anti-harassment programs in place and specialized whistle-blower programs.

“Any rate of sexual harassment and everyday sexism is unacceptable. We are committed to holding investee companies to account on such matters,” said Camille Simeon, an investment director at asset manager Abrdn. “We expect that the findings of this report will motivate other boards into action.”

The Australian Council of Superannuation Investors has said investors will monitor Rio’s progress in addressing the report’s recommendations. Argo Investments said it will clearly bring greater attention to the progress on improving these issues via reporting change.

“We have just seen over and over again these companies that have got policies in place, procedures in place, that on the surface it looks like these issues are being managed,” said Kate Turner, a responsible investment specialist at First Sentier Investors. “But then, when you dig below the surface and have reports like these, you come up with a completely different answer.”

Some investors and executives this week, who asked not to be identified discussing private deliberations, drew parallels with the 2019 waste dam collapse that spurred widespread change, especially added transparency, across the industry.

While both investors and management teams consider how best to address a macho culture that has been embedded since the very first days of industrial mining, the women on the frontlines continue to face sexual harassment as part of their everyday lives.

“It’s dark in the cage, sometimes a man just presses on you with his manhood, you think somebody has urinated or masturbated on you, you just feel the wetness after you leave the cage,” said Mpho, the South African miner.

“When you get to the surface, you say ‘Thank God I am safe.’”

Venezuela Upholds Jail Sentences Against Houston Oil Executives

* Court Decision On The ‘Citgo 6’ Published Late Friday
* Hopes Dashed That Court Would Free Men As Goodwill Gesture

A Venezuelan court upheld the sentences of the six U.S. oil executives known as the Citgo 6, who were jailed for lengthy terms on corruption charges.

The court rejected an appeal by Jose Pereira, a former CEO of Citgo Petroleum Corp, a Houston-based subsidiary of Venezuela’s state oil company, against his prison sentence of 13 years and 7 months, the Supreme Court said in a statement late Friday.

The court also upheld the sentences of eight years and 10 months in prison for Tomeu Vadell, Jorge Toledo, Gustavo Cardenas, Jose Zambrano and Alirio Zambrano. Families of the men had hoped that Venezuela’s court system, which is packed with government loyalists, would release them as a goodwill gesture to unfreeze relations with the government of U.S. President Joe Biden.

The executives were arrested in 2017 after being summoned to a meeting at the Caracas headquarters of state oil company Petroleos de Venezuela S.A., and were convicted in 2020.

Updated: 3-9-2022

Frackers Say Bottlenecks Impede Output Boost As Oil Prices Soar

Shale companies say they are trying to help to fill a gap in global oil supplies after Russia’s attack on Ukraine, but wary investors, supply-chain issues crimp output.

American shale drillers say there are limits to how much and how quickly they can boost shaky oil supplies following Russia’s invasion of Ukraine, cautioning that supply-chain issues, investors wary of overspending, thinning inventories and other problems constrict growth.

Leaders of the fracking companies that helped make the U.S. the world’s top oil producer say they are responding to calls by the Biden administration and others to increase production after oil prices this week topped $130 a barrel and gasoline prices surged, threatening to dent the broader economy.

But the executives say that some investors, who felt burned after shale drillers gave priority to expansion over profits last decade and lost billions, are still concerned that the companies might spend too much if they return to rapid growth.

They also say that a flight of capital from the fossil-fuel industry in recent years has left U.S. oil patches without enough fracking equipment to bring a ton of new wells online, and that a resurgence of go-go drilling would deplete companies’ most valuable drilling locations.

Scott Sheffield, chief executive of Pioneer Natural Resources Co. , said his company, the largest oil producer in the Permian Basin of West Texas and New Mexico, isn’t currently considering lifting its previous long-term target to increase oil production by 0% to 5% a year.

Pioneer’s plan reflects conversations with investors who want the company to retain its renewed focus on free cash flow and dividend yields. But he said those attitudes could change if global markets lose Russian supplies for a longer period, noting that U.S. shale drillers, along with oil-rich nations such as Saudi Arabia and Iran, might be the only ones capable of growing output enough to fill a sizable portion of the gap.

“We have shortages of labor, sand and equipment, and it’s going to take a good 18 months just to ramp it up,” Mr. Sheffield said of the industry. “If it’s a long-term problem, U.S. shale can respond and help the world, but it’s going to take time and a lot of caveats.”

John Hess, chief executive of Hess Corp., said at this week’s CERAWeek by S&P Global energy conference in Houston that his company is looking to increase its oil production in the Bakken Shale of North Dakota by 20% this year.

But he warned that U.S. shale is no longer the world’s swing supplier, as the business has matured. Shale companies have a limited remaining inventory of drilling locations following a decade of exploiting shale rock, he said. The Wall Street Journal wrote about the industry’s emerging inventory problems in February.

“It’s a 10-year-old business. There’s only about a 10-year inventory of shale drilling locations left, maybe 15,” Mr. Hess said. “People are going to be more judicious about how they accelerate in this emergency situation.”

U.S. oil production ended last year at about 11.6 million barrels a day, according to the Energy Information Administration. Many analysts and executives are projecting output will rise by between 500,000 to 1 million barrels a day this year, representing a smaller increase, on a percentage basis, than in years before the pandemic.

Occidental Petroleum Corp. CEO Vicki Hollub said it would be hard for shale drillers to rapidly increase production even in the Permian Basin, the most active U.S. oil field.

Executives, officials and analysts say the extent to which shale companies will turn on the taps remains an evolving issue affected by the world’s escalating response to Russia’s attack. But they generally agree that the primary constraint is nuts-and-bolts limitations in America’s pandemic-battered oil patches, rather than regulatory constraints imposed by the Biden administration.

Amos Hochstein, the U.S. State Department’s energy envoy, said that in recent meetings and phone calls with oil companies, executives indicated the federal government has little to do with their difficulties lifting output.

“I asked most of them, ‘Is there anything you need from the administration to increase production,’ and they said, ‘No, unless you can help me with sand or labor or other supply chains,’” Mr. Hochstein said.

Lenders—who have become more wary of funding oil-related ventures as environmental, social and governance ideas catch on in financial circles—are still unwilling to give money to most of the nation’s crop of oil-field service companies, or to smaller oil producers that want to expand their operations, executives and analysts said.

That has left small but instrumental players short of the financing they need to repair fracking equipment sidelined during the start of the pandemic, or invest in building drill bits, drilling rigs and blowout preventers.

Chris Wright, chief executive of Liberty Oilfield Services Inc., one of the largest U.S. hydraulic fracturing companies, said the nation’s fleet of available, working fracking equipment is almost fully deployed already.

“A lot of equipment has been retired, a lot of equipment is past its useful life,” Mr. Wright said.

He added his company estimated the U.S. oil industry is only going to add about 15 more fracking fleets to the 235 that were operating in key basins by this summer. “The market goes from tight to quite tight,” he said.

The oil industry’s hired hands have raised prices for tools and labor to some extent but aren’t yet benefiting enough from higher oil prices to be able to dispatch with new equipment, said Richard Spears, vice president at energy consulting firm Spears & Associates Inc.

To reduce emissions, Mr. Spears said service companies that provide fracking trucks in recent years have parked many older units that ran on diesel while they have shifted to units with dual-fuel engines that can run on diesel and natural gas.

That shift has left about a third of the fracking trucks in North America in a state of disrepair that will take two years to fix, as companies wait to get key parts such as engines and transmissions for vehicles they had not been using.

“They’ve already got all of their available equipment out there already,” Mr. Spears said. “The constraint on growth is going to be, where do you get another [fracking] truck?”

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