For most of 2015, industry observers have predicted that depressed commodity prices will result in a surge in M&A activity among domestic exploration and production (E&P) companies, as well as a large number of bankruptcy filings by E&P companies. During the first nine months of the year, several factors served to delay the surge. These factors included the benefit of hedge positions that were put on in a higher oil price environment, the significant amount of capital raised by domestic E&P companies in the first half of the year (which is estimated to be approximately $15 billion of equity and $20 billion of bonds),1 the modest but short-lived oil price recovery in May and June, the light touch by banks in the spring redeterminations, and the wide valuation gap between buyers and sellers (which resulted in a substantial number of failed sales processes). However, the 2015 fall borrowing base redeterminations are likely to serve as a catalyst for the predicted increase in M&A and restructuring activity.
The fall redeterminations come at a time when the highly leveraged oil and gas industry faces a high degree of uncertainty and varying levels of distress, driven largely by continued low commodity price levels (for what many increasingly believe will be a prolonged period) and the fact that the favorable hedges will roll off at the end of 2015 and into 2016. In addition, there is increasing regulatory pressure on U.S. banks engaged in oil and gas lending to reduce their exposure to the sector, which many believe could be a pivotal driver of a punitive fall redetermination season across the industry.
Unlike the spring redeterminations, in which banks generally made modest reductions to E&P companies’ credit lines and were less conservative on their price decks than they are likely to be this fall, the fall redeterminations are positioned to extract substantial levels of liquidity from oil and gas companies, leaving them with limited tools to secure alternative sources of capital. As traditional lenders to the oil and gas industry face increasing pressure from federal regulators and the high yield markets effectively close to the sector, cash-strapped E&P companies are going to have to look beyond the traditional commercial banks for much needed capital. If these companies are not successful in raising capital from nontraditional sources, they may be forced into an in-court process. Those companies with sufficient liquidity and proper planning may choose to follow the lead of Hercules Offshore, Inc. — which entered Chapter 11 bankruptcy proceedings in mid-August and obtained confirmation of its prepackaged plan of reorganization a mere 45 days after the bankruptcy filing — to right-size their liquidity risk profiles. Over the past year, approximately 20 oil and gas companies have filed for bankruptcy, many more have recently hired restructuring advisers, and countless others have been flagged by analysts and ratings agencies as over-leveraged, high-default risks.
Federal regulatory agencies, including the Office of the Comptroller of the Currency (OCC), the Federal Reserve and the Federal Deposit Insurance Corp. (FDIC), reportedly (among other cautionary moves) have been warning banks to limit their exposure to increasingly risky oil and gas producers, pressuring banks to tighten and increase the frequency of oil and gas loan reviews, and advising banks that a significant number of outstanding loans to E&P companies should be classified as “substandard” (which generally means that there is uncertainty as to the underlying collateral value and/or the borrower’s ability to repay the loan). These regulatory pressures, together with macroeconomic pressures and the various financial and operational constraints on E&P companies, impede these companies’ access to capital at a time when it is needed most. In some cases, banks are, or may become, unable to continue to extend additional credit to E&P companies, and doors are closing to alternative financing options that have provided much needed liquidity during the first half of this year — namely equity offerings, tapping the high yield bond market, and obtaining second-lien or mezzanine loans. Accordingly, it is prudent for all players in the oil and gas sector to be cognizant of the reported warnings and conservative guidance that federal regulators are espousing with respect to the inherent and emerging risks related to oil and gas lending, particularly as E&P companies face escalating liquidity constraints that will intensify as a result of fall redeterminations if banks concede to the regulatory pressures despite some opposing views on risk levels.
One such federal regulator, the OCC, issued the “Oil and Gas Production Lending” bank examination booklet (as part of the Comptroller’s Handbook) in April 2014,2 which points to the inherent and unique risks in oil and gas production lending, and outlines supervisory expectations and regulatory requirements related to this type of lending. Oil and gas production loans typically are structured as reserve-based revolving credit facilities (or RBLs) that are secured by oil and gas reserves and generally provide for loan terms ranging from three to seven years; loan advances governed by a borrowing base that is primarily derived from the value of the E&P borrower’s proved “reserves” (or the amounts of oil or gas that is expected to be commercially recoverable from a particular region(s) from a specified date forward); and at least semiannual borrowing base redeterminations (in the spring and fall) that are largely based on an updated engineering reserve report and the bank’s current oil and gas pricing policy (or “price deck”). Consistent with the conservative guidance in the OCC Handbook, the OCC appears to be leading the charge amongst federal regulators’ recent efforts to get banks to take a more conservative approach on their loan reviews for E&P companies. In September, the OCC reportedly joined the Federal Reserve and the FDIC in sending regulators to Houston for meetings with bankers from some of the major oil and gas lenders. The OCC reportedly set the agenda for the meetings, which focused on the banks’ examinations and ratings of reserve-based loans, an area in which many of the banks and regulators have conflicting interests and views.
E&P companies, particularly small and midcap ones, rely on RBL facilities for financing the acquisition and development of their oil and gas reserves. In most cases, reserves are an E&P company’s largest asset and dictate the availability under the RBL facility by driving the value of the borrowing base. Since reserves deplete as the E&P company produces oil and gas over time, even as banks pull liquidity — as may be the case in the fall redeterminations if banks decrease borrowing bases and do not provide any financial covenant relief — cash-strapped E&P companies must find the necessary capital to turn their proved undeveloped reserves (PUDs) into proved developed producing reserves (PDPs) in order to restore the collateral to the borrowing base and maintain cash flows.3
While the borrowing base formula established in the loan agreement for the RBL facility technically governs the revolving credit available to the borrower, in practice the borrowing base determination process provides lenders with a great deal of discretion. With respect to setting borrowing base parameters, the OCC advises banks to require geographic diversification of the fields or reservoirs where the relevant reserves are produced; set limits on both the lowest number of producing wells (to limit production concentration) and on the contribution level that any one well can make to the borrowing base; limit the borrowing base to primarily PDP properties that have been producing for at least six months or more and which generate proceeds that are sufficient to amortize the debt over the typical three-to-seven-year term, with a “reserve tail” remaining; and, at the very least, cap the amount that reserves other than PDP reserves may contribute to the borrowing base.4 If banks advance on non-PDPs, such as proved developed nonproducing reserves (PDNPs) or PUDs, they apply varying risk adjustments (or discounts) to each subcategory of proved reserves under the borrowing base before applying advance rates. In practice, very little, if any, institutional credit is extended on account of PUDs. At the same time, while the maximum advance rates applied by each bank vary, the maximum advance rate for PDP reserves typically ranges from 50 to 65 percent of the present value of future net income, and lower advance rates are typically applied to PDNPs and PUDs.5
While observers of the oil and gas industry are acutely aware of the upcoming and oft-discussed fall redetermination season — and the grave impact that it is positioned to have on many in the oil and gas industry (and, in particular, those in the upstream sector) — the technical underpinnings of the redetermination process have not shared the same spotlight. During redeterminations, banks typically rely heavily on internal and/or external engineering consultants for the preparation of the analysis of the reserves that serve as collateral under the RBL facility. Another critical piece to the redetermination is the bank’s price deck, which is typically set at a discount to the forward/futures strip and updated at least quarterly to account for average prices over specified periods (to account for commodity price volatility).
Generally, each bank providing a line of credit under the RBL facility is involved in the borrowing base determination process, which is led by the bank serving as the administrative agent of the RBL facility. The agent will typically have its internal engineer review an engineering report from the borrower’s independent third-party engineer (to the extent provided) and conduct a comprehensive assessment that takes into consideration such factors as the relevant production volumes, operating cost estimates, expected ultimate recovery of reserves and capital expenditures needed to convert reserves into PDPs. Technical adjustments are made based on the bank’s price deck and underwriting parameters, including with respect to risks, reserve splits and concentration levels. In that regard, production lending policies typically require reserve values to be discounted to adjust for risks (to reflect current credit, interest rate, operational, compliance and liquidity risks, among others), reserve splits (to ensure that borrowing bases are derived primarily from properties with PDPs with current production and sufficient cash flow, and to cap and discount higher-risk PUDs and PDNPs) and concentration levels (to control for production and regional concentrations and avoid any single well or field accounting for too much of the value).
The engineering analysis facilitates the development of the bank’s financial projections, which allow the bank to further assess for compliance with the terms of its underwriting policy, including base case and sensitivity case advance rates (to test the borrower’s ability to convert the underlying collateral into cash for loan repayment purposes), reserve tail tests (to account for the projected remaining cash flow from reserves after the projected loan payout and ensure that an adequate reserve tail “cushion” exists) and cash flow projections (to demonstrate the borrower’s ability to cover various projected expenses and debt obligations).6 Numerous other factors may contribute to the redetermination — including, inter alia, the borrower’s ability to manage risk through hedging transactions, reduce operating costs and other expenses, and convert PUDs or PDNPs to PDPs. Finally, once the administrative agent’s engineering and credit personnel arrive at the borrowing base determination they must then propose the borrowing base amount to the syndicate banks, each of which will run its own assumptions and modeling to determine whether or not to approve the amount. Typically, the agent must obtain 100 percent syndicate lender approval to increase the borrowing base, with a lower approval threshold of 66 2/3 percent typically required in order to reduce the borrowing base.
As the foregoing suggests, the volatility in the oil and gas sector, escalating liquidity constraints for E&P companies, the highly discretionary borrowing base determination process and heightened regulatory pressures — as well as the cumulative effect thereof — have the potential to be a catalyst for significant transformation in the oil and gas sector this fall as banks complete their redeterminations. If the fall redeterminations are as punitive as some industry analysts and experts predict, many E&P companies may be left with limited tools to satisfy any resulting borrowing base deficiencies and secure alternative sources of capital to increase production volumes and build up their PDPs. While it is uncertain how E&P companies will respond — will they look to execute debt exchanges, sell noncore assets, seek alternative third-party lenders (such as private equity funds or hedge funds), implement farmout financing arrangements or seek prepackaged Chapter 11 bankruptcy filings? — it is highly likely that the distress in the oil and gas industry will persist in the near term.
Those E&P companies that engage in advanced planning and equip themselves with the right set of legal and financial tools maximize their chances of restructuring out of court or initiating a quick and cost-efficient prepackaged Chapter 11 filing, both of which permit the companies to right-size their liquidity risk profiles and minimize disruptions (if any) to their business operations.
1 The Economist, Fractured Finances: America’s shale-energy industry has a future. Many shale firms do not, July 4, 2015, available at http://www.economist.com/news/business/21656671-americas-shale-energy-industry-has-future-many-shale-firms-do-not-fractured-finances.
2 Office of the Comptroller of the Currency, Oil and Gas Production Lending, Comptroller’s Handbook (April 2014) (the OCC Handbook)
3 Proved developed producing reserves (PDPs) are reserves that are expected to be recovered from completion intervals that are producing at the time of the estimate, while proved undeveloped reserves (PUDs) are expected to be recovered either from existing wells that require relatively significant expenditures for completion and production or from new wells on undrilled acreage where the drilling units offset already productive units (thus, there is reasonable certainty of production once drilling commences). Proved developed reserves are also subcategorized as nonproducing reserves (PDNPs), which are further classified as “shut-in” and “behind the pipe” reserves based on the reason for the lack of current production.
4 OCC Handbook at 17-18.
5 OCC Handbook at 18.
6 Iberia Capital Partners, Energy Lending Industry Review: Investor Conference Call Supplemental Presentation, Jan. 20, 2015, available at http://www.iberiabank.com/about-us/investor-relations/investor-presentations.html; and OCC Handbook at 17-20.
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