Across North America, producers begin to ease toward normal, but uncertainty looms

As the lockdowns from COVID-19 began easing across the North America, a cautious optimism began to creep across the Oil Patch. West Texas Intermediate crude, the U.S. benchmark that briefly turned negative at the end of April, rebounded to about $40 a barrel. For most companies, the price was still too low to justify investment in new drilling, but oil producers waited anxiously to see if it might keep inching higher.

As July wore on, it looked as if prices had plateaued. With new coronarvirus cases spiking across the U.S., companies tried to anticipate what the prospect of new lockdowns might mean for energy demand heading into the fall. At the current prices, even the most optimistic companies see few opportunities for more than incremental steps toward normal, with little chance for growth or increased spending. 

In Canada, companies such as Bonterra Energy, which shuttered many of its higher-cost wells, stood ready to bring them back online as soon as the price justified it. Bonterra is a conventional producer.

Heavy oil, meanwhile, was fetching prices almost $10 a barrel less than WTI, but some oilsands outfits began restarting production anyway. MEG Energy has hedged its bets and pre-sold some of the production at its oilsands facility at fixed prices. 

In West Texas, one of the biggest producers, Diamondback Energy, restarted production at almost all its wells after shutting most of them in during the early days of the pandemic. In May, it cut production by about 9,000 barrels a day, but by mid-July it has restored most of that. Diamondback said it drilled 58 horizonal wells and completed 15 in the second quarter. Meanwhile, some of the U.S. producers wrote down tens of billions of dollars in assets. A recent study by the consulting firm Deloitte found that U.S. shale companies expected to write down about $300 billion worth of assets this year, much of it during the second quarter.

At the same time, as default risks rise, some banks have started selling off loans and credit lines that they extended to oil and gas companies. For example, Hancock Whitney, a regional bank in Gulfport, Mississippi, with branches in Texas and Louisiana that make energy loans, said it would sell almost $500 million worth of its energy portfolio to Los Angeles-based Oaktree Capital Management. Hancock Whitney recorded a $160.1 million pre-tax loss on the sale.

The pullback from banks comes at a critical time for energy companies, who increasingly have relied on financial institutions to fund operations and new drilling as investment capital has dried up. Investors have soured on the energy sector after years of poor returns despite the shale drilling boom.

While banks worked with producers during the bust in 2014, continuing to lend and helping oil companies restructure debt, the pandemic has prompted a second bust in just six years, and banks now seem less willing to work with companies through the current crisis.

Several smaller producers, including Antero Resources Corp., Centennial Resource Development and Oasis Petroleum, have seen their credit lines slashed in recent months. U.S. banks hold about $650 billion in energy company loans, which account for 3.5% of all bank assets nationwide.

With demand and prices weak, and drilling activity slowing, some companies are looking for deals. In late July, Chevron agreed to buy Houston-based Noble Energy for $13 billion, prompting speculation among some analysts that the long-awaited merger boom may finally be underway. Given the weak price environment and uncertain demand outlook from the COVID-19 pandemic, larger companies with deeper financial pockets may be better able to endure the likely turbulence of the next few years.

Chevron settled on Noble after being outbid by Occidental Petroleum for Anadarko Petroleum last year. In that deal, Chevron offered $50 billion, only to be topped by Oxy’s $57 billion bid. Oxy, however, has struggled to pay off debt from the transaction since then. The Noble deal, if it’s approved by shareholders, would give Chevron 92,000 additional acres in the Permian Basin in West Texas, 35,000 in the Eagle Ford Shale in South Texas, some 336,000 acres in Colorado and offshore assets in West Africa, and the eastern Mediterranean off the coasts of Israel and Cyprus.

At the moment, however, additional acreage in U.S. shale basins may not be much help. The coronavirus has hit West Texas particularly hard, as oil demand shrank by more than 20% this spring. By early July, the rig count in the Permian Basin had fallen to just 125. In mid-March, more than 400 rigs were working in the region. Unemployment soared to 13.4% in May from 2.1% a year earlier.

Layoffs have stretched across the industry. Houston-based oilfield services company BJ Services joined the growing list of industry bankruptcies in July and has said it may have to layoff 537 people statewide if it can’t find a source of financing. The news came on top of another 446 job cuts from around the industry the same week. Schlumberger, which posted its weakest quarterly sales in 14 years, said it would slash one-fifth of its workforce, or about 21,000 workers. As of early July, the COVID-19 pandemic had resulted in about 94,000 jobs lost in oilfield services alone, according to the Petroleum Equipment and Services Association.

While oil and gas producers continue to struggle, renewables are faring somewhat better. As Congress debates the next COVID-related stimulus package, seven Republican senators — including Lisa Murkowski, who represents oil-rich Alaska — called for a range of clean energy incentives to be included in the aid package. The proposal includes extending soon-to-expire tax credits as well as cash advances for renewable energy projects. (A number of large companies, including Oxy and Duke Energy, have asked for similar benefits that would allow them to cash out future tax credits immediately.) The moves are designed to provide the industry with much-needed liquidity and get clean energy workers furloughed as a result of the pandemic back to work.

Renewables are also playing a key role in the growing number of small power grids being deployed around the U.S. A new Wood Mackenzie study found that the U.S. installed a record 546 “microgrids” that can distribute power independent of traditional utilities. The grids have a variety of uses, including providing emergency power in the event of outages.

The consultancy predicts that as the number of microgrids increases, they will rely more on renewable power sources, including wind, solar and hydropower, accounting for 35% of the installed capacity in five years.

In the meantime, many producers across North America are hoping that a recent prediction from the International Energy Association that the worst effects of COVID-19 on oil demand have passed, proves to be true. From northern Canada to South Texas, oil executives are waiting, poised to open the taps at the first sign of certainty.

Read the latest issue of the OGV Energy magazine HERE.