• –As a result of the slide in oil prices, US based exploration and production companies have decreased access to traditional borrowing based financing. An uptick in oil and gas bankruptcies has resulted from the declining oil price.
  • Private ownership of oil and gas predominates in the US. Exploration and production companies make “leases” with the private landowners, and enter into operating agreements with potential investors in order share business risks. However, the enforcement of these agreements in a US bankruptcy can be problematic.
  • –A complex patchwork of federal and state laws will impact the options available to energy producers in a US bankruptcy.


Since the third quarter of 2014 in the United States, the appetite for new lending to small and midsized exploration and production companies (“E&P Companies”) has largely disappeared for several reasons. The most significant reason is the drop in oil prices to the WTI (West Texas Intermediate) Spot close at Cushing, Oklahoma in the $40 per barrel range, although it has recently recovered to the $50 per barrel range as of the end of July 2015.

E&P loans in the United States are made available via a borrowing base, the value of which is driven by reserve reports prepared by reserve engineering companies. These reserve reports are generally only prepared half-yearly and incorporate the current prices for oil and gas as at the report date. Most reserve reports are prepared as of 31 December and 30 June of each year. However, the reports take several months to prepare and are not  due to the Lenders until early March and early September of each year, although the value of the reserves is based on 31 December and 30 June numbers. Hence, E&P Companies with borrowing base credit facilities began feeling the effect of this price slide beginning in March 2015, based on the price of oil and gas as of the previous 31 December. However, the decline  in prices and decreases in borrowing bases has been mitigated to some extent by borrowers having active hedging programs that limit their downside in a declining oil price market.

The E&P lenders have taken a similar approach to the decline in oil and gas prices to that of the 2008-09 decline, which is to work with the E&P Companies as much as possible, tinker with the credit agreements around the edges and only take action on those E&P Companies that are in critical condition. That said, prior to the price decline, the average  E&P Company was only approximately 60% drawn on their credit facility. Hence, even with a significant borrowing base reduction, most E&P Companies still have availability under their credit facilities. Nevertheless, the initial drop in borrowing base availability did cause a number of E&P Companies to be required to repay a portion of their credit facility, which they were not be in a position to do as a result of their drilling commitments. This first group became the watchlist credits, workout counsel was engaged for a number of these credits and special asset groups began to monitor all oil and gas credits generally.

The price decline and related decrease  in borrowing base availability has also led  to a number of high profile Oil and Gas (O&G) Company Chapter 11 proceedings throughout the United States. We have also begun to see credit facility amendments  that are purely workout in nature: waiving a covenant violation, adding specific borrower undertakings to pay for lender’s cost of restructuring advisers, lenders waiving a “going concern” paragraph in borrower’s audit letter etc.

We have had discussions with several capital market investment advisers in the E&P space regarding the current state of the market. The reports here were consistent. Public offerings for virtually all E&P Companies have been shelved at this time. Therefore, the public capital markets are generally not available at this time and we would not expect them to open up in the second half of 2015 if prices remain where they are today. This  lack of public capital market availability will place additional pressures on companies that anticipated using those markets in the capital structure for continued E&P development and commitments. As a result of these changes, more expensive specialty lending groups have already begun lending into the E&P space. These specialty lending groups were previously limited to very distressed companies due to the general availability of fairly inexpensive money. Additionally, private debt and equity has also seen an increase in the E&P investment space since December 2014. Finally, M&A activity is on the increase, with private investor groups looking for distressed assets and large financially stable O&G Companies looking to acquire valuable assets at distressed market prices.

Oilfield services companies have already begun to feel the squeeze of the drop in oil prices. Rigs are being mothballed in basins around the country. Oilfield service companies have been asked to drop their prices immediately by between 10% and 40%, whether or not they have a contract in place. These changes are being driven both by industry players as well as professional advisory companies that have been engaged to right-size the E&P companies. These oilfield service companies are generally governed by ABL credit facilities that make credit available based on their hard assets and the value of their contracts. This revenue squeeze  is likely to create opportunities for specialty lenders as well as in the merger and acquisition space. However, there are over-leveraged and inefficiently run companies that cannot operate in a $55 to $60 per barrel environment, and we have already seen bankruptcies from WBH Energy LP (a Texas drilling company) and GASFRAC Energy Service Inc (a Canadian waterless fracking company).


Ownership of land within the US generally will include the right to extract and sell minerals from under the land. Instead of dealing with a sovereign Crown, energy producers in the US usually have to contract with multiple private owners of the minerals.

Most landowners will prefer that a knowledgeable oil and gas E&P Company handle the extraction. The landowner typically conveys a “working interest” in the minerals to the E&P Company in exchange for “royalty payments”. The terms of the royalty payment are negotiable, but generally represent a fraction (say 1/8th) of the proceeds of production on a cost free basis.

“Working interests” in the minerals are conveyed by means of a “lease”, and the owners of mineral interests and working interests are often referred to as lessors and lessees. The lessee receives the right to extract and sell the minerals for a fixed period of time and as long thereafter as there is production of the minerals. Oil and gas leases are typically either “unless” or “or” forms. The “unless” form provides that the lease will terminate during the primary term unless “delay rentals” are paid; delay rentals are regarded as payment by the lessee for the privilege of deferring or delaying drilling. The “or” lease contains only  a contractual obligation to pay if drilling is not commenced by the time limit set in the lease. Delay rental “unless” leases have largely fallen from favour and most leases are now “paid-up” leases. Working interests conveyed by a lease do not exist in perpetuity. Instead, the rights conveyed by the working interest revert back to the landowner owner if certain terms and conditions are not met.

In the UK, ownership of the oil or gas in the ground remains with the Crown until extraction. However, because in most US jurisdictions the lessee holds a fee simple interest in the minerals, “reserve based lending” provides a significant source of capital for E&P Companies. US courts have affirmed the attachment of liens to mineral leaseholds.

However care must be taken in analysing the character of mineral interests in the US for purposes of perfecting liens. The exact nature of the property right created by an oil and gas lease varies from state to state. In Texas and Pennsylvania, for example, oil and gas leaseholds are classified as real estate, while in Kansas, a lease is essentially a license to go upon the land in search of oil.


The variety of state laws governing the conveyance of interests in minerals leads to complexity in how US bankruptcy courts will determine the rights of the landowner in the event an E&P Company files for bankruptcy. Section 365(a) of the US Bankruptcy Code provides that a bankruptcy trustee (or debtor in possession) may assume or reject any executory contract or unexpired lease.

Oil and gas leases considered to be fee simple interests under the governing state law do not constitute “unexpired leases” under the Bankruptcy Code and therefore s 365 does not govern their assumption or rejection. However, in states where oil and gas leases constitute leasehold interests rather than fee interests, s 365 governs their disposition.

In those states where s 365 applies, the debtor must cure any defaults in order to assume the lease, and must provide “adequate assurance” of future performance. In such states, the debtor must pay all past due royalties in full, and provide assurance it will comply with the terms of the lease in the future. Section 365 allows assumption notwithstanding any lease term that would otherwise permit the landowner to terminate the lease based upon the insolvency or financial condition of the lessee.

By contrast, in those states where an oil and gas lease is considered to be a fee simple interest, s 365 does not apply, and the unpaid royalty owner holds a claim against the debtor to be settled in the bankruptcy case. Furthermore, s 541 of the Bankruptcy Code precludes any forfeiture of the lessee’s interest in minerals based solely upon the insolvency or financial condition of the lessee.


Companies wanting to develop oil and gas interests tend to involve other investors to share the risk. In US jurisdictions, the Joint Operating Agreement (JOA) describes what the investing party is to do and what the party owning the oil and gas lease is to do.

A JOA provides the contractual basis for the cooperative exploration, development and production of oil and gas properties among multiple leasehold co-tenants. The E&P Company often assigns undivided fractional shares of those oil and gas leases to third parties. The result is that any given oil and gas property is typically concurrently owned by numerous co-tenants. The parties may hold leases that cover various undivided interests  in a single tract of land, or they may own leasehold interests in nearby tracts of land and wish to pool their interests together in order to drill a well.

Under a JOA, the leasehold co-tenants appoint one party as “operator”, who then has full control of conducting and directing all operations in the contract area, under the confines of the JOA. The remaining co-tenants are then considered “non-operators”, who only retain indirect control of the operations in the contract area, such as voting on subsequent operations, electing whether to consent to subsequent operations, and certain inspection rights.


In light of current oil and gas market distress, we can expect the terms of JOAs will be tested in US based bankruptcies. The JOA gives rise to a credit risk for all of the working interest owners which are parties to the agreements, both operators and non-operators. Operators frequently make advances on behalf of non-operators for both capital expenditures and lease operating expenses. The typical process under the JOA is for the operator to make cash calls for drilling expense and the costs of production. Payment terms for these cash calls range from 30 days in advance or payable in arrears and the non-operators are obliged to pay the cash calls at that time without question. Any objections to the charges are to be made through an audit process specified in the JOA.

Upon the bankruptcy of the non-operator, claims for both capital expenditure amounts and for unpaid lease operating expenses generally will be unsecured claims against the non-operator. Operators, on the other hand, often market hydrocarbons for the non- operators. Prior to the operator paying over the proceeds of the sale of such hydrocarbons, the non-operator will be taking a credit risk on the operator. In that circumstance, the bankruptcy of the operator will result in the non-operators being left with claims for hydrocarbons that have been produced and sold prior to the bankruptcy.

JOAs are always held to be executory contracts and can thus be assumed or rejected under s 365 of the Bankruptcy Code. If the debtor rejects the JOA, generally the non- breaching counterparty will have an unsecured claim for damages against the debtor party. One consequence of rejection of the JOA, is that the non-breaching counterparty should be able to enforce its rights under the JOA against the breaching debtor party, except that any money damages will be treated as any other unsecured claim against the debtor, and will likely be compromised.

In contrast, if the debtor assumes the JOA, it will be required to “cure” all payment defaults within a reasonable time after assumption. Furthermore, a party assuming a JOA will be required to provide adequate assurance of future performance under the agreement if there has been a default. The debtor must assume the entire JOA, it may not pick and choose which terms to assume.

Bankruptcy cases frequently culminate in sales of the debtor’s assets, and prospective buyers often link the sale of assets to the assumption and assignment of contracts. Assumption and assignment of an executory contract or unexpired lease requires notice to the non-debtor party and a showing, among other things: (i) that any defaults pursuant  to the contract sought to be assigned have or will be cured; and (ii) of “adequate assurance of future performance” under the terms of the contract on the part of prospective assignee. Anti-alienation provisions which limit or prohibit the assignment of a JOA are unenforceable in bankruptcy. Therefore, a debtor for the most part has the power to assign a contract or lease without the consent of contract counterparties, which would be required in the absence of bankruptcy.

It should be noted that the US Bankruptcy Code does not impose a strict, fixed period within which the debtor must decide to assume or reject the JOA. During the period while the debtor is deciding whether to assume or reject a JOA, generally the non-debtor party must continue to perform its obligations. During that “gap period”, the non-debtor  party will bear the risk and uncertainty that results from not knowing whether the contract will be rejected, assumed, or assumed and assigned. Particularly with “core contracts”  that are central to a producer’s business, the uncertainty surrounding whether such an agreement will be assumed or rejected and whether the counterparty will have sufficient capital to meet its ongoing obligations thereunder can layer on enormous additional risks for capital intensive projects. The US Bankruptcy Code permits the counterparty to reduce this uncertainty by seeking to shorten the time period for a debtor to assume or reject the JOA.


In the US, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), imposes joint and several liability for the release of a hazardous substance on the owner or operator of a facility and on any person who arranges for the disposal of a hazardous substance off site. Petroleum, including crude oil and any fraction thereof, and natural gas are excluded from the definition of “hazardous substance”.

However, state laws impose a separate layer of regulations dealing with releases of hazardous substances, as well as the “plugging and abandonment” of oil and gas wells. Each  oil and gas producing state has its own industry regulator. Because the laws of each state can vary greatly, it is critical to have locally licensed oil and gas and environmental counsel available to address the environmental ramifications of drilling operations in states where an E&P Company operates.

The federal bankruptcy laws generally require trustees to comply with state laws in administering their estates. Consequently US courts have held the bankruptcy trustee has an obligation to plug the unproductive wells, if the obligation arose during the bankruptcy proceedings, and that such obligation has an administrative priority status.


Providers of oil field services are more likely to face liquidity crises in the next six months than are E&P Companies. Many service companies had borrowed heavily to upgrade equipment, and now find themselves on an unstable financial footing.

E&P Companies have mitigated against the decline in oil prices and decreases in borrowing bases by active hedging programs that limit their downside in a declining oil price market. However, the public capital markets are generally not available to E&P at this time, and it remains to be seen whether their capital needs can be met by means of specialty lending groups, private debt, and M&A transactions.

In contrast to mineral production in the UK, the US legal landscape is comprised of a patchwork of federal and state laws. In matters of oil and gas, state and local laws must be taken into account in devising the appropriate legal strategy.