More than 120 E&Ps filed for bankruptcy protection in the U.S. during 2016 and 2017, representing approximately $80 billion in liabilities. An important element of the bankruptcy process is the ability of companies to reject uneconomic and burdensome contacts, helping to correct the subject companies’ cost structure. These contract rejections have—and will continue to—affect oilfield service and midstream companies. Here are the effects of E&P bankruptcies on the energy supply chain and recommendations to better navigate the changing environment.

Specifically, two aspects of E&P restructurings are causing issues for supply companies: contract rejections and capex reductions. In a Chapter 11 bankruptcy, debtors have the ability under certain circumstances to reject executory contracts that are no longer providing value to the estate. Examples include leases, master service agreements, transportation and gathering agreements and other contracts where parties have not completed performance.

Rejection of an executory contract relieves the debtor from performing its remaining obligations and can no longer be compelled to perform. The other party is entitled to an unsecured claim equal to damages caused by the rejection. These damages are generally calculated as the present value of the lost profits.

Emas Chiyoda Subsea Ltd. is a recent case with significant contract rejection implications. Under bankruptcy code, Emas would be required to pay counterparties the damages–the net profits lost—from contract terminations. Future payments for three out of the seven contracts Emas plans to reject are estimated to be $342 million. To put that in perspective, all of the debtor’s other unsecured debt and trade payables combined totaled approximately $277 million. Future payments under a rejected contract are not equivalent to lost profits by which a damage claim is determined; however, reference to the future payments amount illustrates the potential magnitude of the impact of contract rejections.

As E&P companies’ profitability declined, many looked to the rejection of uneconomic executory contracts for relief. The rejection or renegotiation of these contracts transferred the problem from the E&P to the service provider in several ways that were not immediately obvious. Three segments affected by E&P bankruptcies include onshore services, offshore services and midstream services.

Onshore service providers

Providers of onshore oilfield services have, perhaps, felt more than others the effects of the rejection or cancellation of master service agreements (MSA) and operating contracts by bankrupted E&Ps.

Distressed E&Ps have streamlined supply chains by consolidating vendor bases and have reduced the risk of disruption by upgrading to higher credit quality counterparties. For longer-term contracts, there has been a distinct shift away from providers with weaker balance sheets and restricted access to capital. Also, as the industry operates at lower utilization levels, operators are seeking better equipment from providers; in many instances, this belongs to larger service companies. The result has disproportionately distressed many smaller service providers, which generated revenue through a limited number of high-value contracts.

For example, driller Helmerich & Payne Inc. reported in its quarterly financials that backlog has fallen from $5 billion in the third quarter of 2014 to $1.4 billion in the second quarter of 2017. Of the $3.6-billion decrease, U.S. onshore activity accounted for $2.9 billion of the decline—approximately 80%. During 2016, H&P notably saw 50% of its drilling contracts cancelled. Not every risk can be completely mitigated and the current downturn may prove to be one such risk. However, various service providers have successfully reduced their exposure by managing credit and counterparty risks, providing commodity-indexed pricing and maintaining high safety standards.

Rig contracts are off-balance-sheet obligations. While such contracts are, therefore, not separately valued to either party, they do constitute significant backlog to both parties. These contracts contribute to the value of the company as a whole during transactions and are often mentioned by bond-rating agencies during credit reviews, highlighting another way contract rejections affect drilling service providers.

Offshore service providers

Offshore service providers have also been significantly affected. Offshore projects require significantly higher capital commitments and longer time horizons. As a result, service providers are often engaged via long-term contracts that allow E&P companies to establish cost limits and increase long-term budgeting accuracy. Consequently, many service providers mitigate their own risk of cost inflation by entering long-term contracts for sub-contracted services. As E&Ps filed bankruptcy and moved to reject contracts, or simply renegotiated contracts out of court, many service providers were left without contractual revenue streams while still required to service their own executory contracts.

Contract terminations, whether market-driven or through the bankruptcy process, can cause considerable distress. Take the example of Ocean Rig UDW Inc. In the first quarter of 2016, three Ocean Rig contract cancellations took place, totaling approximately $580 million in future revenue. For instance, the termination of the contract for the drillship Ocean Rig Apollo could have triggered a mandatory prepayment of Ocean Rig’s credit facility of almost $145 million. Ocean Rig began restructuring discussions and filed for bankruptcy before the quarter’s end. Even though Ocean Rig was unable to avoid bankruptcy, the release of the credit-facility prepayment provided Ocean Rig with much needed financial flexibility.

Prepayment clauses in debt instruments amplify operational setbacks by combining reduced cash flows from operations with increased cash outflows for financing. Negotiating debt instruments is a balancing act and a complex legal and financial process. However, prioritizing the elimination of prepayment clauses can serve to make an economic downturn more manageable.

Capital-intensive businesses such as E&Ps and offshore service providers can partially protect their stakeholders by including more severe downside scenarios when preparing projections and forecasting liquidity needs. Traditional banks, partially driven by new Office of the Comptroller of the Currency (OCC) regulations, have included additional sensitivities in the determination of borrowing bases. The OCC has, in part, been successful in reducing risk for traditional banks, but, at the same time, has caused a migration by E&Ps away from banks toward obtaining debt capital from non-bank sources.

Midstream service providers

While often considered a stable business model, midstream companies are far from immune to the E&P downturn. Oftentimes, midstream contracts are structured with costly development plans and production-growth targets that may or may not occur.

Unlike offshore service providers, midstream operators often have better leverage in bankruptcy negotiations as economic gathering and transportation alternatives are limited in many U.S. basins. Quicksilver Resources Inc., which was a Barnett Shale-focused E&P and already struggling with a low gas price before the oil price downturn, filed for bankruptcy protection in early 2015. Under the rules, it renegotiated its midstream contract with Crestwood Equity Partners LP. The rejection became an important and contentious aspect of this bankruptcy case, which was ultimately settled out of court.

While Quicksilver set the stage for attempting the rejection of midstream contracts in bankruptcy, Sabine Oil & Gas Corp. was one of the first E&Ps to successfully reject a gathering agreement. This ruling—in the first quarter of 2016—set a precedent for midstream contract rejections, often including “take or pay” provisions. Following Sabine’s example, Magnum Hunter Resources Corp., Emerald Oil Inc., Linn Energy Inc. and Triangle Petroleum Corp. were among E&Ps to attempt rejection of midstream contracts in their bankruptcy filings.

An important aspect driving the damages related to midstream contracts was the take-or-pay provision. These created misalignment between the E&P and midstream provider when oil prices dropped significantly. Lower E&P revenues, thus reduced capex budgets, resulted in both a lower price per barrel and lower quantity of oil produced. The take-or-pay provision was a hedge for midstream operators.

Renegotiated contracts have moved from take-or-pay to provisions that align the two parties’ profitability. A provision that has gained popularity is linking transportation and gathering fees to the price of oil. This linkage provides both parties with better exposure to rising oil prices, while allowing E&Ps to control costs in downturns.

Effects of capex reductions

In response to the low commodity price environment, E&P companies decreased capex budgets by more than 40% from 2014 levels. They have limited drilling activity to only the highest priority areas and expanded cost-reduction initiatives, including contract renegotiations. Confronted with limited market activity, increased price competition and low workforce utilization, service providers have frequently been required to make significant price concessions to retain contracts—oftentimes at levels well below historical margins.

Offshore service providers were particularly affected as offshore E&P companies typically possess higher cost structures and are more sensitive to price fluctuations. The rig count in the U.S. Gulf of Mexico fell from more than 60 in 2014 to less than 30 in 2016 and fewer than 20 today. As activity swiftly declined, several service providers quickly became distressed and were forced into bankruptcy. Although oil and gas prices have modestly improved since the first quarter of 2016, E&P companies have continued to preserve capital and decrease operational costs, reducing the number of market opportunities for service providers.

One example that illustrates the impact of capex reduction in the offshore service industry is the CHC Group Ltd. bankruptcy. Prior to filing for bankruptcy in May of 2016, CHC Group Ltd. was one of the world’s largest commercial helicopter service providers with a fleet of 67 helicopters owned and an additional 163 leased. The majority of its business involved providing long-distance, crew change services to offshore oil and gas fields throughout the world. In fact, for the three years ending April 30, 2015, approximately 90% of its revenue was generated from contracts with oil and gas producers; its financial performance was closely tied to the health of the energy industry.

Prior to its restructuring, CHC generated revenues from fixed monthly fee and hourly rates and contracts included four- and five-year terms with extension provisions. However, the contracts contained provisions that allowed customers to terminate early without significant penalties. As commodity prices began to rapidly decline E&Ps began reducing crew changes while also demanding significant price concessions from service providers.

The market demand for flying hours and helicopter fleet utilization levels dropped alongside the decrease in oil and gas prices. Facing lower utilization and pressures from E&P customers, service providers began to engage in intense price competition to secure bids for the limited amount of work available. To preserve capital throughout the downturn, CHC implemented a series of cost-reduction initiatives to improve the efficiency of its supply chain, including reducing headcount, centralizing operations and closing certain facilities. Despite this, its liquidity continued to deteriorate due to the fixed costs associated with the 163 helicopters the company leased from third parties and significant debt servicing obligations, ultimately precipitating the company filing for bankruptcy.

It’s not clear what actions were available that could have prevented CHC’s bankruptcy. Mitigating CHC’s exposure by aligning the terms of its helicopter leases with the terms of its contracts with E&P companies may appear good in theory, but it is impractical in operation. Diversification out of revenue-weighting to E&P customers to reduce risk is another good solution, but it is also difficult to implement. One of CHC’s competitors, Bristow Group Inc., teamed up with an Uber-like helicopter ride-sharing service, Blade, to shuttle passengers to various vacation destinations in the Northeast. So far, this initiative has not had a material impact on the company. Credit and counterparty risk can mitigate some of the exposure, but not all. This is especially true in an environment where an entire industry, and therefore CHC’s customer base, is severely affected.

Resiliency

Rejection of executory contracts and leases are an important aspect of the successful restructuring of many distressed E&P companies. However, rejection of executory contracts pushes (part of) the financial problem down the supply chain. This type of trickle-down economics is impacting oilfield service and midstream companies.

The recent downturn emphasized the importance of risk management, specifically credit, counterparty and concentration risks. Reducing counterparty risk through proactive management, whether driven by business partner solvency or simply contract treatment through industry cycles, is a critical step in risk minimization.

Planning and preparing for a downside scenario in capital-intensive businesses is paramount. Capital availability for E&Ps has significantly changed since the downturn began, as traditional bank lenders have incorporated additional sensitivities in their borrowing-base determinations.

The resilience of the energy business is demonstrated by its creativity in designing contracts that re-align interests among counterparties. An example is the midstream contract that now includes escalating fees based on oil prices. These contracts create win-win situations in rising oil price environments and allow for flexible downscaling in depressed price environments. They also reduce the risk of trickle-down damages and better address cyclical financial problems on an industry-wide basis instead of pushing them down the supply chain.

Paul F. Jansen is a managing director in Conway MacKenzie’s energy practice. He performs strategic, financial and operational analyses on behalf of debtors and creditors to determine business viability and to develop survival, sale or liquidation plans. Jansen is a certified insolvency and restructuring advisor, certified public accountant, accredited in business valuation and a register accountant in the Netherlands.

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