E&P Commercial Lending: Shrink to Fit

[Editor's note: A version of this story appears in the August 2020 edition of Oil and Gas Investor. Subscribe to the magazine here.]

In these days of duress and distress, a CEO or CFO asking the bank(s) for more money resembles an antsy teenager asking for some cash and the car keys. Father replies, “Not until you clean up your room and bring your grades up.”

As one source said, “Even banks with good clients are not advancing higher borrowing bases. They’re saying in effect, ‘Do not ask us for more money.’”

This year Job 1 for E&Ps has been to clean up their balance sheets, renegotiate their public debt obligations and navigate the loan redetermination season with their commercial bankers.

It hasn’t been easy for many. For the 36 public E&P companies that it tracks, Reuters found the average cut to their borrowing base this spring was 10% to 20%, or an aggregate $7.5 billion.

S&P Global Ratings said the majority of the E&Ps it has rated as speculative grade reported “material” cuts to their reserve-based loans (RBLs) this past spring.

“For 80% of these companies, the elected commitments now equal the borrowing base amounts (up from 40% pre-redetermination), which could be troublesome in the fall,” according to the S&P Global Ratings report. “This redetermination cycle has been more prolonged and less forgiving than previous cycles.”

For example, Oasis Petroleum’s base was reduced to $625 million, and it had drawn $522 million of that as of March 31.

Long-time observers have seen these ups and downs many times. Earthstone Energy Co. executive chairman Frank Lodzinski has seen this play out before, having been in the oil business for 48 years.

“It’s a bit ironic that I am ending up my career in this industry in a collapse like we had in 1986, which was near my start. But as far as Earthstone goes, we never went broke before, and we’re not starting now,” he said.

Lower oil and gas prices—and commercial bankers’ desire to lower their risk exposure to energy—were the understandable reasons for the tough redetermination season just past. Falling commodity prices and fewer drilling rigs at work meant less proved reserve value to be used as collateral.

“Banks look at everything in a company. They rip it apart and then come back with their redetermination,” said Rob Sabo, director of interest rate trading at Aegis Energy in Houston. “As the industry faces all these issues, the banks are cutting the amount producers can borrow, and they are also increasing the credit spread [the points above Libor].”

The spread, or bank’s margin, is calculated based on a borrower’s risk profile, the quality of its assets, cash flow ratios, other metrics and the outlook for that particular business—all part of the underwriting process.

“The point is [that] you, the borrower, may have no control over the rising credit spreads we are now seeing, but you do have control over the base rate because you can put on hedges. You can lock in a variable or floating interest rate or put on an interest rate swap,” he said.

Sabo said a company can do such a swap on a monthly basis or longer term. “Credit spreads for shale producers are expanding, but at least you can lock in the floating rate side of it,” he said.

Aegis’ advisory service on interest rates began in March to enhance its long-time business in commodity price hedging.

Regardless of whether a borrower can hedge the commodity price or the cost of money, by most accounts this fall’s loan redetermination season will be just as tough as it was this spring, people said. The outcome hinges on the price deck banks are able to use at the time.

“Banks are less forgiving now than they were in 2015 to 2016,” said Rob Johnson of EIG, a firm that makes first lien and other types of investments as an alternative to commercial bank loans. In May the firm closed on nearly $3 billion of new capital to be used as secured debt for companies in need of capital.

“Then, the banks were more optimistic about a rebound in oil prices, and they were more patient. To some degree, they engineered a soft landing. But the companies that saw a soft landing then are some of the ones having greater losses now. In today’s market it’s very hard to sell assets, whereas in 2015 and 2016 you still had some kind of A&D market,” he said.

Feeling the pinch

As 2020 unfolds, signs of distress throughout the industry have not abated: fewer well completions, impaired loans, huge reserve write-downs, bankruptcies and credit downgrades by the rating agencies like S&P Global Ratings and Moody’s. E&Ps were certainly feeling the pinch.

Too many dire predictions color the scene. S&P listed 17 energy companies in default near the end of June; about half of those had already filed for Chapter 11 proceedings to restructure their debt through the courts. Some had trouble completing distressed exchange offers.

You have seen the data: Moody’s Investors Service said in January that North American oil and gas companies have more than $200 billion in debt maturing over the next four years, with about $40 billion due this year alone. In the last downturn, Moody’s said companies issued $250 billion of new debt from January 2015 through September 2018. Could they do so again?

Rystad Energy warned that if oil remains low, about $30/bbl, 73 companies might be at risk of having to declare bankruptcy this year to restructure their debt. Even though the price is above that figure, Rystad said many companies are still threatened.

A recent Deloitte study said 30% of all shale E&Ps are technically insolvent, even at $40/bbl. It predicted reserve write-downs for the second quarter could top an astounding $300 billion, with consolidations, forced or otherwise, to follow. That is a big hole to dig out of.

In the interim companies strapped for cash have been drawing more from their bank line, sometimes 100%, leading their bankers to call for an end to so-called “cash hoarding.” Wells Fargo said earlier this year that private shale operators have drawn down 70% of their bank lines, and more than a third of energy high-yield bonds were trading at distressed prices, per Bloomberg data.

Having a bank line fully drawn down chokes off any further liquidity, so if a company’s wallet still comes up short, it has to sell assets, issue equity in an unforgiving market or try to add additional banks to its list of backers. Banks cannot provide 100% financing on development because the upside is capped, but the downside risk is not. And because of regulatory changes in 2016, they cannot fund an acquisition where the bank’s debt portion would be more than 50% of the total deal.

Cowen & Co. analysts said in a late May report that these credit concerns may be overblown, at least for the companies it covers. It conceded the E&P sector has serious debt issues to handle, with average leverage in 2021 estimated at 3.6 times. It cited Pioneer Natural Resources Co., Diamondback Energy Inc. and EQT Corp., among others, that have issued five- or six-year notes to pay down near-term debt maturities. It also said the industry as a whole is about 19% drawn on its revolving credit facilities.

Remedies and options

Options companies can pursue include “kicking the can down the road” by extending the date of the spring redetermination to later in the fall or reducing the credit line on an interim basis until the fall. Those companies that can have issued new public debt. In one week in June alone, 25 companies accessed $18 billion in public debt.

“With spending cut to the bone, operators likely exploring debt exchanges or relying on borrowing bases that are still generally supportive, it does not appear that a wholesale capital structure disruption is set to take place,” according to the Cowen report.

This might ultimately put a ceiling on the group’s equity rally that occurred from the April lows.

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To cope, companies have slashed spending dramatically in favor of servicing debt, maintaining dividends or other financial considerations. Some 14 of the 27 E&Ps Cowen covers were running a mere two rigs or less in late May, about a 60% decline from fourth-quarter 2019 activity.

Although E&P executives have reacted fast to the troubles caused by the coronavirus and the Saudi-Russian price war debacle, they need headroom to make it to January 2021. They need to buy time, use exchange offers to pay down their revolvers, hold tight to liquidity and survive to drill another day.

“For the most part, banks were tightening liquidity and borrowing base capacity, not enough to put companies in real jeopardy but rather to give them enough time to get through 2020,” said George Ward, in the Houston office of PJ Solomon’s energy advisory practice. He said, “Just give them enough to pay down the revolver some and get through the rest of this year.”

To help its energy clients cope, Solomon has been facilitating conversations on one restructuring, some public mergers of equals and advising strategic or financial players that are bidding on so-called “363 deals” (acquisition of assets out of a bankruptcy).

Ward said he thinks new money will come into the space from the financial community, including options such as direct lending and secured offerings, which will inject new equity and debt into E&Ps that sorely need it.

It’s a very fluid situation, but I think banks are working with companies to get them at least to the fall redetermination.
—George Ward, PJ Solomon

The industry “may see some consolidations [occur] after a restructuring, since many of these companies have too much debt to combine and you can’t refinance the consolidated entity,” said Opportune’s David Baggett during a webcast. Dire circumstance may force their hand.

Certainly consolidation among E&Ps is an option that would create companies with larger balance sheets that spread general and administrative expenses over a wider set of assets under one umbrella. But with so little visibility, it is hard to assign a meaningful value to a company or an asset package.

Finding value

Rumors circulated this past spring after a Reuters article claimed commercial banks were facing several customer defaults and bankruptcies that would force them to take over assets, but Ward does not see it that way. If banks tighten up too much and a borrower has to file for bankruptcy or try to sell oil and gas assets, there is not enough value in the market right now. It’s a losing game.

“It’s a very fluid situation, but I think banks are working with companies to get them at least to the fall redetermination,” Ward said. “I’m more focused on what the price of oil will be in June 2021 and December 2021, and whether companies need to hedge or put more rigs to work.”

Companies might try to add some more assets to the reserve report or amortize a loan deficiency over several months.

“The deficiency amortization is the choice everyone is going to elect,” said Trevor Wommack, partner with Latham & Watkins LLP, speaking on a webcast the law firm held in June to explore options for borrowers.

Adding reserves could be difficult, as there is little visibility for acquisitions right now, he added.

The average drop in the banks’ price deck this past spring was 15%, but some faced a 20% drop, resulting in a corresponding borrowing base decrease.

“This magnitude of drop in the borrowing base is difficult to cure,” said Catherine Ozdogan, another partner with Latham & Watkins LLP. “A downward redetermination is meant to bring all the parties to the negotiating table. It’s customary that 100% of the banks [in a loan syndicate] must approve an increase in the base but only 65% a decrease.”

At that point, the other options include forbearance of debt payments due or other changes to a company’s capital structure and bank covenants. When an E&P elects not to make an interest payment, that starts a 30-day clock of forbearance, and presumably at that point the company is already in discussions with creditors anyway.

If it cannot make a borrowing base deficiency payment, then it has to set up milestones to prepare for bankruptcy, appoint a restructuring adviser, execute a PSA for potential asset sales and so on.

Forbearance can last up to 120 days, thus giving the borrower time to refinance the RBL or close a transaction to pay it off.

“Lenders don’t call the shots; they don’t tell the company what to do,” Wommack said. “If banks dictate what approach a company takes to address liquidity, that gets into too much liability [for the bank].”

Pick your poison

Though no bank yet admits to taking over oil and gas assets, and none of them claims a desire to do so, even if they did, banks would preferably only hold assets until the M&A market recovers and they can unload, but the time line on that is still uncertain. Also, do they replace the existing E&P management team or let it stay during the process? After all, someone has to operate the fields, pay the royalty checks and manage the accounting. Do they consolidate the assets of more than one distressed company into one chunk and place that under one management team?

“You have to pick your poison,” Wommack said. “If it’s a fire sale [or Chapter 7 liquidation] or banks end up owning assets at the end of a very time-consuming process. And each bank in a syndicate of many banks ends up being an equity owner in a special purpose vehicle. The time and effort it takes for banks to manage owning E&P assets is too much … so they try to kick the can to an M&A market opening back up.”

For companies that were not doing well before this spring’s twin tragedies of the virus and the oil price war, the spring redetermination cycle was basically “used as a hammer” after the price crash, Ozdogan said.

Wommack said he has seen instances where a company’s hedge book value is 150% of the company’s borrowing base.

“Just let that sink in for a minute,” he said. “If you’re in a deficiency situation, you can sell your hedge position … and put that cash on your balance sheet.”

Milestones can always be extended as long as the parties negotiating a company’s financial position see that some progress is being made, Ozdogan said. Given the many options that companies and bankers can pursue, and amid extreme price volatility and economic uncertainty, the road ahead looks about as straight as the auto climb up Pike’s Peak.