Oil And Gas Bankruptcies Grow As Trumponomics Hits Shale Industry (#GotBitcoin?)
Smaller drillers, which account for sizable part of U.S. oil production, are struggling to pay off hefty debt burdens. Oil And Gas Bankruptcies Grow As Trumponomics Hits 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.
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.”
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