The Fuse

Crackdown on Shale Debt Won’t Necessarily Drive Steep Production Declines

by Nick Cunningham | April 14, 2016

Much has been made about the ability of U.S. oil and gas drillers to tweak their drilling practices, cut costs, and squeeze more oil from an average well. These efficiency gains have been the key to keeping many producers afloat during the market downturn.

Just as important has been the industry’s access to finance, which has allowed companies to continue to drill and meet debt payments despite the sharp fall in cash flow.

“The volume and velocity of deal flow was such that it was a rubber stamp. They were not scrutinizing price assumptions and forecasts. Everyone was open for business. It was full on, full throttle.”

Wall Street has not fully closed its doors to the oil and gas industry, but nearly two years into the downturn, indebted drillers are finding it increasingly difficult to convince Big Finance to maintain its generous policies towards shale producers. However, because of the way the industry is structured, even if banks scale back on their cash injections it does not necessarily mean a precipitous decline in oil production is forthcoming.

Banks underwrote the oil and gas boom

Major banks thought lending to oil and gas companies was a sure bet, even to smaller drillers who did not have rock-solid credit. Dennis Cassidy of the Dallas-based consulting firm AlixPartners, said that banks did not think twice about lending to risky oil and gas companies. “The perception was the risk was reasonably low,” Cassidy told Bloomberg in an interview. “The volume and velocity of deal flow was such that it was a rubber stamp. They were not scrutinizing price assumptions and forecasts. Everyone was open for business. It was full on, full throttle.”

However, federal regulators have stepped up their scrutiny of energy lending, pressing banks to take a more cautious approach to companies that have little capacity to meet debt payments. Banks argued that even if floundering energy companies did not have enough cash flow, their assets could be liquidated, ensuring full repayment and leaving little risk for the lender. But with a large part of the industry trying to sell off assets all at once, liquidation is no longer a sure bet. The Treasury Department’s Office of the Comptroller of the Currency, which oversees national banks, issued new lending guidelines in March, tightening lending terms by putting more weight on the total debt levels of borrowers.

In fact, there is a growing realization among lenders that the energy sector is not as risk-free as once thought. Wells Fargo, one of the largest energy lenders, was owed $9.6 billion by oil and gas companies at the end of 2015, and the bank has earmarked $1.2 billion to cover for potential losses. According to Moody’s, in a worst-case scenario the major banks JP Morgan Chase, Citigroup, Bank of America, Goldman Sachs and Morgan Stanley would need a combined $9 billion in capital to account for energy loans that have gone bad.

According to Moody’s, in a worst-case scenario the major banks JP Morgan Chase, Citigroup, Bank of America, Goldman Sachs and Morgan Stanley would need a combined $9 billion in capital to account for energy loans gone bad.

Wells Fargo is not too concerned, however, since energy only accounts for about 2 percent of its overall lending portfolio. But another looming problem for lenders is the much larger pile of money that has been promised to energy companies if needed. The Wall Street Journal reported that 10 of the largest U.S. banks still have $147 billion in unfunded credit to energy companies, a large sum that could be tapped if drillers choose to do so. If oil and gas companies use these credit lines further, it will only deepen the exposure for the major banks at a time when they are trying to back away from the industry.

This large volume of unfunded loans is “the most unpredictable part of our assumptions” about exposure to the energy sector, JP Morgan’s CEO Jamie Dimon said in February. And, of course, a company struggling with debt is exactly the type of company that would seek to max out credit lines. “Let’s not sugarcoat it. This is not necessarily a loan a bank wants to make at this point,” Glenn Schorr, a bank analyst at Evercore ISI, told the WSJ.

Credit redetermination

Energy loans are often determined using a combination of factors, including a driller’s reserves, hedges, expected production levels, as well as tax and other parameters. The borrowing base is adjusted typically twice a year based on changing market conditions, usually in the spring and fall. The industry is in the process of completing the latest credit redetermination period, and after a relatively lenient assessment last October, banks could cut credit lines by as much as 30 percent this time around.

According to Reuters, by mid-April banks had cut about $3.5 billion in credit—equivalent to one-fifth of the total credit available. In March, Whiting Petroleum, a shale driller that focuses on the Bakken, saw more than $1 billion cut from its credit line. At the current rate, credit reductions could reach $10 billion by May.

That could push a few more struggling oil and gas companies into bankruptcy as liquidity dries up. There have been at least 59 oil and gas producers that have filed bankruptcy since the beginning of 2015, a number that is sure to rise in the months ahead. Deloitte says about one-third of U.S. shale producers are in danger of falling into bankruptcy in 2016. Fitch Ratings estimates that 60 percent of speculative-rated debt is in danger of default, while JP Morgan made a more conservative estimate, projecting that 36 of about 150 energy companies with a speculative credit rating could default by the end of 2017.

Bankruptcies don’t necessarily take resources offline

The 59 oil and gas drillers that have gone under only account for about 1 percent of total U.S. oil production.

Some argue the cash crunch is exactly the bitter pill needed to force a contraction in U.S. oil production, a necessary adjustment to balance global oil markets. But just because a company is forced into bankruptcy does not mean that oil stops flowing from its wells. According to Reuters, Mangum Hunter Resources, a small oil and gas driller, has managed to keep nearly all of its 3,000 wells operating despite the fact that it filed for Chapter 11 bankruptcy protection in December. Since creditors still want some sort of repayment, both the lender and the borrower have every incentive to keep production as high as possible, and while data is often hard to come by, Reuters says that many companies in the Chapter 11 process have not seen their operations interrupted.

Moreover, counting the number of bankruptcies is the wrong metric to watch when trying to assess when and how fast U.S. oil production will fall. Aside from the fact that bankruptcies do not necessarily mean production will fall, the 59 oil and gas drillers that have gone under only account for about 1 percent of total U.S. oil production. Taking a broader definition, Rob Thummel of Tortoise Capital Advisors tells Reuters that 1 million barrels per day (mbd) of U.S. oil production, or ten percent, is “financially challenged.” Still, that means that 90 percent or more of U.S. oil production is not at risk because of a credit event.

Greater production drop-offs expected at $30 oil

Much more important than a bankruptcy filing is the massive cut back in capex, which to be sure, is heavily dependent on access to credit. But instead of the number of companies filing for bankruptcy, it is the sharp reduction in spending plans and drilling activity—combined with natural depletion—which is resulting in steady declines in U.S. oil production.

EIA’s forecast production declines are assuming an oil price averaging just $34.60 per barrel in 2016 and $40.58 in 2017. If prices happen to rise much higher, revenues—and access to credit—will rebound as well.

The U.S. has lost nearly 700,000 barrels per day of oil production since peaking at 9.69 mbd in April 2015. The latest weekly estimates put U.S. output at 9 mbd, and EIA projects that the major U.S. shale basins will continue to decline in May. Led by losses in the Eagle Ford (expected to fall 62,000 barrels per day between April and May) and the Bakken (down 31,000 bpd), the U.S. could lose as much as 114,000 barrels per day next month.

The decline will continue for quite a while—EIA sees U.S. oil production averaging 8.6 mbd in 2016, falling further to just 8.0 mbd in 2017. In its latest Short-Term Energy Outlook, the EIA forecasts production will hit 7.9 mbd in the third quarter of 2017, or 1.8 mbd lower than the April 2015 peak.

On the other hand, those figures are assuming an oil price averaging just $34.60 per barrel in 2016 and $40.58 in 2017. If prices happen to rise much higher, revenues—and access to credit—will rebound as well. If that occurs, drillers will return to the oil patch.