Even if he hadn’t been paying attention to Covid-19 news or watching the price of oil ($13.24/bbl today), Chris Atherton, president of EnergyNet, would still be able to foretell the doom ahead for the oil sector just from the phone calls he fields from people looking to sell oilfields on his online platform. Dealing in oil and gas operations, royalty interests, undeveloped acreage, and more —it’s like Ebay, for oilfields.
A year ago, Atherton, 43, was getting a lot of calls from companies eager to divest non-core assets and clean up their balance sheets. Back then, with oil prices at $60, the interests they sold went for an average price of $42,000 per net flowing barrel per day (thus a 100 bbl per day field costs about $4.2 million). As 2019 went on, buyers got more picky, and sellers more desperate. A lot of undrilled acreage didn’t sell at all.
In late February, the calls began drying up. As the Corona-crisis hit and oil prices went into freefall, companies yanked listings. “It’s on pause,” says Atherton. “When you have big fluctuations in volatility, the asset divestitures market seizes up.” That’s especially the case with management teams who have accepted the end is nigh and are determined not to be second-guessed in court.
For how long depends on prices. That per-flowing-barrel valuation has plunged with the price of crude, to less than $20,000 in the 40 or so deals that EnergyNet transacted in March and April. As badly as companies would like to jettison assets, “if there’s negative oil prices, a prudent judge will delay a sale.”
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Atherton’s incoming calls now are from restructuring teams wanting to prep EnergyNet. “The wave is coming.”
Atherton, ex-Enron, joined EnergyNet soon after its founding in 1999, about the same time, he says, as the launches of Socks.com and AskJeeves. Competitors have come and gone, leaving EnergyNet to sell 200,000 properties over 20 years, for $6.8 billion. Atherton says that EnergyNet have verified that today’s 40,000 registered users have access to $17 billion worth of dry powder ready to make deals.
“If it’s any silver lining, there’s lots of buyers.” Their killer app: digitization of every bit of available information about an asset and its neighborhood. “We show all the production nearby. It contextualizes the value, like Redfin or Zillow,” says Atherton. In the past two years EnergyNet has transacted more than $5 billion in properties, taking a cut of 2-3% on every sale), including post-bankruptcy sales for the likes of Samson Resources, Linn Energy, EnerVest, Swift Energy and Sanchez Energy.
Atherton has watched the evolution of the shale revolution, and has marveled at the undying optimism of drilling engineers. He has in recent years collected screen shots of favorite pages from oil company investor presentations, which show cross sections of reservoir rock pierced by as many as 40 wells per square mile — a vision of efficiently mass producing oil that has never lived up to the hype. Did they really think it could work? “I don’t think it was nefarious or fraudulent,” says Atherton, just overly optimistic.
The big banks are now standing up teams to deal with assets — essentially in-house oil companies. Some specialize in it, like BOK Financial, controlled by Oklahoma oil billionaire George Kaiser. But it’s generally not something they want to do, says Georgetown University Prof. Reena Aggarwal. Oil adds a lot of risk to banks balance sheets, especially assets that weren’t good enough to keep companies out of bankruptcy in the first place. Banks want oilfields off their books, but don’t want to crystallize losses. So they hold, and wait.
This down cycle won’t end without some marquis names going into Chapter 11. Before Covid-19 many bankers considered Chesapeake “too big to fail” with access to ample capital to keep limping along. Now the opinion has changed. With $9.4 billion in debt requiring $650 million in annual interest payments, and operating income set to get cut in half this year, Chesapeake has limited runway left. Its equity market cap is down to $300 million, while Chesapeake bonds maturing February 2021 traded Tuesday at 7.75 cents on the dollar (down from 95 cents in early January) according to FINRA data — as if holders anticipate a total loss. “If they don’t do a voluntary restructuring at some point, they will not be well positioned when the industry turns around,” says a consultant who advises banks on oil assets.
Indeed, when the industry turns around, there will be some surprises waiting for them down in those oil reservoirs. With Covid-19 lockdown evaporating 40% of gasoline demand, storage tanks in the U.S. will hit “tank tops” within weeks. With no place to stick their crude — at any price — producers have begun the labor-intensive process of shutting-in their wells. Already billionaire Harold Hamm’s Continental Resources has shut in all of its roughly 200,000 barrels per day of production in North Dakota, and declared force majeure, refusing to sell contracted oil to pipelines at negative prices.
It’s not like turning a water faucet on and off. “Shut-ins are not easy decisions. When production shuts-in, problems arise. Multi-phase well flows begin to separate out, while problematic hydrates, waxes, asphaltenes form which will have serious economic implications,” noted analyst Bob Bracket of Bernstein Research last week, sharing numerous examples of fields around the world that were flowing more than 1,000 barrels per day before being shut-in due to low prices — then never started up again. This is a frightful proposition when buyers value oilfields based on how many barrels of oil they flow per day. Uncertainty can be expensive. A shut-in field might only sell for half the price of an otherwise identical one still flowing healthily, says Atherton.
But how low can prices go? Last week a few dozen prompt month futures contracts for West Texas Intermediate crude traded below -$30 per barrel — meaning that sellers are paying buyers to take their oil away because they have nowhere to store it. Likewise, oilfields can sell for “negative” value because of the size of their attendant liabilities tied to plugging wells and remediating land. Atherton says that although EnergyNet usually makes its commission off of auction proceeds, they’re now able to sell these negative-priced assets by accepting a success fee.
One company with huge potential remediation costs that has analysts concerned is California Resources Corp., which was spun out by Occidental Resources in 2014 to take Oxy’s giant old California oilfields, and loaded up with debt, including more than $4 billion due by the end of 2022. CRC’s average all-in cost per barrel, including $19 in cash operating costs, $8 in interest, and $5 in overhead (per Bernstein), adds up more than $35 per barrel — too high for current oil prices.
Yet CRC can’t easily shut in its operations, many of which rely on continuous injection of steam down into reservoirs to coax stubborn oil out. Add low oil prices to California politics and CRC might soon be unable to stay in business. “Sometimes it feels like I’m watching a comedy, sometimes a tragedy, but increasingly it’s a horror story,” says Clark Williams-Derry with IEEFA. CRC’s 8% bonds maturing in December 2022 changed hands in January at 45 cents on the dollar, according to FINRA data. Last trade on Tuesday was at 1.62 cents.
It seems fitting that California’s oil-rich San Joaquin Valley was the setting of the best oil movie ever: Daniel Day Lewis’s There Will Be Blood.
Too soon to tell, but Atherton expects that in a year or so, oil company bleeding will turn into a flood of assets available on EnergyNet, bringing buying bonanza not just for private equity types, but for any accredited investor who ever dreamed of owning a slice of oilfield. If you’d prefer to stick with stocks, analyst Bob Brackett at Bernstein suggests that the most action (and risk of bankruptcy) will be in those thinly valued equity issues balanced atop mountains of debt, and suggests that dedicated bottomfeeders could take a flyer on the biggest losers so far, including Whiting Petroleum, Centennial Resource Development, QEP, Chesapeake, Callon Petroleum, Denbury Resources, Extraction Oil & Gas, Laredo Petroleum, Chaparral Energy and California Resources — keeping in mind that some will be a total loss. Brackett’s preferred oil producers, still near record lows, but considerably safer, include ConocoPhillips, Hess, EOG Resources, Apache, Concho Resources and Pioneer Natural Resources.
Atherton and his partners realized coming out of the 2016 oil recession that EnergyNet’s fate was a little too closely tied to the oil industry. So they’ve been working to diversify their platform and now are providing an exchange for 23 commodities, including helium, geothermal, surface rights for wind and solar, and even timber. They know well how tough it is to break into a new business: timber people ignored their listings, until Atherton ordered his team to build a new entryway, called Timber Online. It worked. “It’s a perception thing,” he says. “Now they think we do it all the time.” Just a little insurance, in case this oil thing doesn’t work out.
For more on EnergyNet, check out my 2016 story:
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