It’s been a wild ride in the oil and gas industry, and it’s not over yet. Even after recent improvements, oil prices have fallen nearly 60% from their 2014 highs, and natural gas prices have remained low. To put these price moves in context, since 1982 there have only been three other periods of time when crude prices have fallen by more than 50% in six months: the 1986 oil price collapse, the 1991 Gulf War and the 2008 financial crisis.1
This recent price drop has created stress across the energy industry, from exploration and production (E&P) enterprises and oilfield service providers to midstream and downstream companies. And numerous ancillary businesses will also likely feel the pain, ranging from the hotel operator in Williston, ND, to the car dealer in Midland, TX. Residents and businesses in boom towns that have seen exponential economic growth in the past five years may quickly feel the impact of the “bust” cycle that typically follows a “boom” in commodity prices.
For U.S. E&P companies, the challenges are unique. In speaking with our clients and others connected to the industry, we have identified several themes that could play out over the coming months:
Determining UCC, State Mineral Rights
Many U.S. E&P companies have multiple farm-out or joint operating agreements that are potentially governed by multiple state laws. Further complicating matters, many of them funded their initial developments with net profit interests or overriding royalty interests subject to interpretation of state real property laws.
Secured creditors should be diligent in ensuring that their liens are properly perfected on both leases and mineral rights. In a restructuring, determining priority between federal UCC and state mineral rights as creditors fight for their fair shares can become extremely complicated and litigious.
Structural Changes to Procurement
Over the past couple of years, companies across the oil and gas industry have been more concerned with service quality and speed than unit price when buying goods and services. When crude prices are above $100 per barrel, companies can afford to “leave money on the table” because of the ROI associated with new production. But now that oil prices have dropped dramatically, resetting supplier pricing should be one of the highest priorities for all oil and gas, service and related companies. In high-demand locations (e.g., Permian, Bakken, Eagle Ford, and so on), falling labor prices should translate to savings across the industry.
Suppliers that provide E&P companies drilling rigs, equipment, transportation and water management services are already feeling the impact as E&P companies retrench their operations and reduce their capital expenditures in the face of declining prices. These oil field service companies have reacted quickly to the turmoil in the oil markets by reducing headcount and idling equipment where possible; however, many of these suppliers funded their rapid growth through debt issuances and are significantly levered in the face of a severe contraction of their revenues. Most oil field service companies could potentially face revenue declines of at least 20% to 40% during 2015 based on announced reductions in E&P drilling, and backlogs are shrinking.
Nevertheless, companies have the opportunity to structurally change their approaches to procurement. Given the current market, companies can consolidate their supplier bases, leverage their total volume, and identify partners to carry forward into the future. Using a strategic sourcing process, companies can take advantage of the current pricing and the consolidation of the supply market, and partner with strategic suppliers to ensure continuity, improve service levels and maintain pricing at a level below the market high. Companies that do so can see higher margins as commodity prices rise.
Historically, many E&P companies have developed robust hedging programs to protect themselves against volatility in commodity prices. These programs typically have been mandated by senior lenders, as part of credit agreements. To minimize the cost of executing these programs, most companies hedge their production (or the volume of production stipulated in their credit agreements) for the subsequent 12-month period. During 2014, many of these hedge programs were introduced when crude and natural gas prices were trading at the equivalent of $100/bbl. Since then, the values of these hedge portfolios have increased significantly, providing a much needed buffer to E&P companies’ balance sheets and P&Ls.
As a result, several E&P companies have realized significant cash payments upon settlement, and reentered new hedge contracts at the current, lower pricing levels. These types of transactions enable them to be opportunistic in realizing value from a well-placed asset on their balance sheets. Unfortunately for many producers in high-cost basins, or those with cost structures limiting the ability to profitably extract production at the current market rates, many high-dollar hedge contracts will begin to expire over the falling two to three quarters and be replaced with hedge contracts at the current forward curve for oil and natural gas. As a result, these producers face two potential pitfalls: 1) The stream of cash-flows they receive will be greatly diminished, as current prices are approximately 40% less than the average hedge contract issued in the spring of 2014. 2) The contracts can limit their potential cash-flows if prices improve significantly.
U.S. Crude Oil Reserves
In recent years, most U.S. exploration and production has been funded with debt, with an expectation that future revenues will enable debt service and repayment. Falling prices mean less cash-flow to fund such service, and the market for selling reserves up front has cooled off, making monetization of reserves at attractive valuations more difficult.
According to the U.S. Energy Information Agency, in 2013 the U.S. surpassed both Russia and Saudi Arabia in oil and gas production, a position the U.S. last held in 2002. This trend continued in 2014, and is expected to continue through 2016 due to the dramatic growth in proven reserves in the U.S. (Exhibit 1) that stems from hydraulic fracturing and other technological advances.
Although rig counts have declined in these fracking plays, according to analysts at IHS, an estimated 2,500 to 3,500 wells have been drilled but not completed. As costs to complete these wells come down due to oilfield supplier price declines, the wells will become profitable at lower prices. This “storage in the reservoir” option for producers will create a buffer against a significant price rise and is likely to result in an elongated recovery period.
The primary source of short-term liquidity for many producers is a financial product similar to an asset-based revolver called the reserve-based loan (RBL). An RBL is similar to an asset-backed loan, with one primary difference: The borrowing base is determined for each producer following a detailed review of the company’s portfolio of producing assets, its hedge program, its capital expenditure program and its overall cost structure. One of the biggest determinants in a company’s reserve base is the company’s mix of oil, gas and gas liquids, coupled with an assessment of whether or not those reserves are producing. The lenders then assign a borrowing base available to the company whereby they can utilize it similar to a traditional revolver. Typically RBL borrowing bases are determined twice a year: in April and in September.
During 2013 and 2014, many producers relied heavily on their RBLs to fund production increases and are now in danger of being in an overadvance situation with their lenders. While borrowing base deficiencies may be cured by adding properties to the collateral base, many independent E&P companies may not have such flexibility, or their additional properties may be subject to the vagaries of the market (e.g., lower market prices, high extraction costs, significant depletion rates, etc.). To cure these overadvances following a redetermination, borrowers will likely need to raise additional liquidity via the capital markets to repay the RBL with secured or unsecured notes. Alternatively, some producers may look at selling non-core assets to raise the required capital; however, given the generally depressed nature of oil and natural gas properties in the current market, these may pose a significant challenge.
Strengthening Liquidity and Balance Sheets
During this period of significant volatility in the commodity markets, many producers and suppliers may be planning on riding out the storm or raising additional capital when needed. For many companies, these strategies may not be the best approach. Given the volume of new production and reserves discovered in the past five years, the industry may be facing a prolonged period of prices in the $50-60/bbl range that will require structural change at many companies. In addition, the capital markets have been extremely volatile in recent months for high-yield issuers; timing will be an important factor for companies to execute capital markets transactions (i.e., raising additional equity or debt). In this environment, companies should be considering opportunistic capital raises to shore up their liquidity and balance sheets.
Across the oil and gas industry, companies have been scrambling to adjust to the dramatic drop in commodity prices. For U.S. E&P companies, the challenges are unique. These companies should be taking a proactive approach to positioning themselves to weather a potentially prolonged downturn in the oil and gas sector.
Becky Roof is a managing director in Turnaround and Restructuring Services, Rob Albergotti is a director in Turnaround and Restructuring Services and Michael Chiock is a director in the Enterprise Improvement practice, all at AlixPartners.
1. AlixPartners analysis of WTI front-month pricing charts dating back to 1982