Reserve Base Lending’s Past—and Future—in Shale Production

Interest rates could play a large role in the future of North American shale oil and gas production. A new report indicates that fluctuating interest rates could partially overtake efficiency gains and improvements achieved in shale.
By Luke Geiver | July 14, 2017

Interest rates could play a large role in the future of North American shale oil and gas production. Efficiency gains and operational improvements achieved by North American shale oil and gas producers during the oil price downturn that started in 2014 and ended in late 2016 have solidified shale production as a multi-generational industry. But, a new report indicates that fluctuating interest rates could partially overtake those gains and improvements as a major factor driving growth in the industry.

Amir Azar, a fellow at the Center on Global Energy Policy—an independent, balanced, data-driven analytics group that provides information to policymakers looking to navigate a complex world of energy—analyzed the role interest rates have played and will play in the health of the North American shale production industry. Azar documented how interest rates have impacted the practice of reserve base lending (RBL) for energy producers and offered insight into how lenders have changed their practices towards energy producing borrowers following the low oil price environment.

Easy access to low-cost debt helped fuel the shale revolution, Azar said. Many small- and medium-sized producers have relied on RBL to receive bank debt financing for the drilling and expansion of oil and gas reserves. Without deep-pockets or cash-on-hand as larger, traditional oil production firms typically have, RBL is needed to help below-investment-grade and investment grade firms start and grow their own production. RBL financing is linked to the value of the oil or gas reserves that an exploration and production company owns. His study, released this spring, “Reserve Base Lending And The Outlook For Shale Oil And Gas Finance,” explains how RBL shaped shale production up to 2015 and how things will be different in the future.
 
RBL Basics and Complexities
Oil and gas reserves are classified into three categories: proved reserves, probable reserves and possible reserves. Lenders only extend credit against a company’s proved reserves. An independent reserve and production engineer calculates how much the bank can lend based on the value of the proved reserves. Up to 2015, RBL financing was the borrowing method of choice, in part because of the low interest rates associated with the debt and the strategic nature of many small- and mid-size operators. Between 2005 and 2015, E&P aggregate debt increased by 300 percent, from $50 billion to $200 billion, according to Azar’s report. At the same time, interest expenses related to the debt increased by only 150 percent, from $4 billion to $10 billion. “Therefore, debt increased twice as fast as interest expense, indicating a gradual decline in borrowing cost,” the report says, or, “Simply put, low interest rates incentivized higher debt to boost the return per share.”

Because low-cost debt was easy to obtain, shale industry entities became accustomed to outspending cash flow to fund growth with new debt instead of utilizing a combination of debt and cash on hand. Revenue generated from oil production was not, in some cases, enough to fund operational growth or acquistions.

The issue with that strategy appeared when oil prices began to fall. Through SEC rules, companies can only book or count reserves that are scheduled to be developed or produced within five years. But, as the study says, in a low-oil price environment, corporate cuts in capital spending can alter the development time line of certain reserves beyond the SEC’s five-year window. The sustained low oil price period ruined roughly $160 billion of book equity value for E&Ps that was linked to their proved reserves that they had planned on developing with oil prices at a higher range.

The History of Debt and Shale Growth
For shale producers who lost the value of their reserves due to low oil prices, some were forced into bankruptcy. Others were able to redo or renegotiate the stipulations placed on their loan repayments or in the way they could spend the borrowed money. Since 2015, many banks have added new stipulations to the covenants that come with RBL financing packages for shale producers, Azar noted. Most RBL financing packages now include hoarding language, deposit account control agreements and minimum hedge requirements. Because some shale producers foresaw an impending bankruptcy, many took all of the remaining credit and cash from their revolving credit facilities in a move that would help them pay for legal fees and restructuring during a bankruptcy proceeding, Azar said. Because of that, banks will no longer allow the debtor to hoard cash for those purposes. In addition, banks are also asking producers to hedge more of their production to ensure and entrench their position on a producer. The account control agreements limit what money can be spent on to a greater extent.

Because interest rates played such a large part in allowing RBL financing to thrive during the shale boom of 2008 through 2014, Azar believes interest rate hikes are very important to the future growth opportunities of U.S. shale energy production. Although many producers have opted to grow or maintain operations by investing or using only cash-on-hand, many producers still need to utilize debt to stay relevant. “With the expectation the Fed will continue to increase rates, oil hovering at $50 a barrel, and higher credit spreads, small and midsize North American E&Ps may face the same old challenge of high cost of capital,” Azar said.

Author: Luke Geiver
Editor, North American Shale magazine
701-738-4944
lgeiver@bbiinternational.com