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January 6, 2015
Oil and Gas Restructurings:
Exploration and Production Companies Face Unique Issues
The recent drop in oil prices will likely spur a flurry of industry restructurings, governed by a
complex set of bankruptcy and state laws.
At the close of business on December 31, 2014, the price of West Texas Intermediate crude oil was
US$53.27 per barrel — an approximate 50 percent decline from the price of US$105.24 at June 30,
2014. Natural gas has faced a similar decline, falling approximately 36 percent over the same period.
This steep decline in commodity prices is already reflected in the trading prices of many exploration
and production (E&P) companies’ debt securities. In December 2014, E&P company high yield debt
rated BB was generally off 15 to 20 points since the summer peak, and the broader B / CCC rated E&P
high yield debt universe was off more than 30 points since the summer peak. Some of these
companies are also facing bond maturities in 2015 and 2016, while others may be required to reduce
capital expenditures at the expense of longer term cash flows. If commodity prices settle at or near
today’s prices, several companies in the upstream segment of the market very likely will face significant
liquidity crises, while others may require a more comprehensive financial restructuring.
The current downturn is a reminder that oil and gas exploration and production has always been a
cyclical business. Memories of the last downturn in the sector may have faded but investors should
keep in mind some of the unique industry and legal issues involved in oil and gas finance.
Reduced Borrowing Bases under RBL Credit Facilities
E&P companies rely on reserve-based revolving credit facilities, or RBL facilities, for their working
capital needs and to fund their exploration and development programs. Availability under RBL facilities
is permitted up to a borrowing base set by lenders primarily in consideration of the value of the
borrower’s proved oil and gas reserves. The value of those reserves is determined by reference to a
“price deck” which the lenders under the RBL facility set. Although RBL facilities typically require
lenders to consider the value of the borrower’s proved reserves in setting the borrowing base, RBL
lenders generally also are permitted to consider such other information as the administrative agent
deems appropriate in its sole discretion. In short, the borrowing base is whatever the lenders say it is.
RBL facilities typically require scheduled redeterminations of the borrowing base on a semi-annual
basis; once in the spring and once in fall. Lenders also generally are provided the right to a single
special redetermination between scheduled redeterminations. In addition, incurring additional long-term
debt often triggers automatic reductions to the borrowing base (often a US$0.25 reduction for each
US$1.00 of additional debt incurred), and the lenders often are permitted a special redetermination in
connection with any termination of commodity hedging contracts.
In times of steep declines in commodity prices, most E&P companies will find the availability for
additional borrowings under an RBL facility reduced, in some instances to a level below the aggregate
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principal amount of loans outstanding, resulting in a borrowing base deficiency. Once a borrowing base deficiency has occurred, most RBL facilities will provide the borrower the option to add additional collateral with a value equal to at least the deficiency amount or to pay down the outstanding loans in an aggregate amount equal to the deficiency in a single payment or in equal installments of three to six monthly payments. In a typical reserves-based financing, substantially all of the collateral has already been pledged to the lenders as collateral, which leaves the borrower only the option of paying down the debt. Choosing to repay the deficiency amount in installments gives the borrower a short window of time to raise capital, including by selling properties or securing additional credit through junior lien or subordinated debt, in order to avoid an event of default under its RBL facility.
ORRIs, NPIs, and Production Payments
Investors in the upstream sector can purchase overriding royalty interests, net profits interests, production payments and a variety of other interests in the production of oil and gas, all with similarly confusing names. However, the nature of the interest the investor purchases, and the recovery on that interest in a bankruptcy, can vary significantly.
Broadly speaking, an overriding royalty interest, or ORRI, is an interest in oil and gas that is free of the expense of production, and similar to but in addition to the usual landowner’s royalty reserved to the lessor in an oil and gas lease.1 The owner of an ORRI is entitled to his or her share of the production — without the requirement to share in any of the costs or expenses of production — but has no rights with respect to operations. A net profits interest, or NPI, on the other hand, is a share of gross production from a property, measured by net profits from operation of the property.2 The owner of an NPI receives a share of the profits from the sale of production after expenses but is still not responsible for any expenses and typically does not have rights with respect to operations. In either case, an ORRI or NPI is typically conveyed to investors with documentation reflecting the parties’ intent to convey an interest in real property. Whether the interest conveyed to the investor is an interest in real property or a form of financing can enormously impact the value of that interest.
If characterized as an interest in real property, the ORRI or NPI is excluded from the debtor’s estate. The Bankruptcy Code specifically excludes from property of the estate “any interest of the debtor in liquid or gaseous hydrocarbons to the extent that … the debtor has transferred such interest pursuant to a written conveyance of a production payment [as defined by section 101(42A)] to an entity that does not participate in the operation of the property from which such production payment is transferred….”3 The Bankruptcy Code defines a production payment as a type of “term overriding royalty” or “an interest in liquid or gaseous hydrocarbons in place or to be produced from particular real property that entitles the owner thereof to a share of production, or the value thereof, for a term limited by time, quantity, or value realized.”4 However, even if not meeting the definition of a production payment under the Bankruptcy Code, the transaction still may be considered a conveyance of real property under applicable state laws.
The treatment of production payment sales under the Bankruptcy Code presents its own set of issues centering around whether the production payments are part of the bankruptcy estate. Section 541(b)(4)(B) of the Bankruptcy Code provides a safe harbor for assignees, codifying the generally accepted view that assignees of production payments take title to the property, which then ceases to be property of the estate.5 However, the specific language of the safe harbor creates uncertainty in certain circumstances. The safe harbor provides that “property of the estate” does not include production payments that are assigned “to an entity that does not participate in the operation of the property from which such production payment is transferred.” This language may be read to imply that the safe harbor is only available to assignees who provide financing, and not to assignees who received production payments as compensation. There is little case law on this issue. As such, Section 541(b)(4)(B) provides fertile ground for arguments between debtors and operating assignees over whether the assigned interests in production payments should be excluded from the debtor’s estate.6
Additionally, the parties’ intent to create an ORRI and convey real property interests will not necessarily preclude a court from recharacterizing the transaction as a financing arrangement under certain circumstances. In one recent case, a bankruptcy court denied a summary judgment motion made by a party seeking a ruling that prepetition transactions with the debtor were real property conveyances, despite the fact that the relevant documents characterized the transactions as ORRIs.7 Applying Louisiana law, the bankruptcy court held that “the parties’ intent as to the legal effects of their contract
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has no bearing on whether those legal effects are in fact created”
8 and, where the economic substance of the transaction points to a disguised financing, a court may recharacterize the real property interest as a debt arrangement.9 Although the court ruled at the summary judgment stage, the implications are substantial, as recharacterization of an ORRI as a disguised financing would mean that the non-debtor’s interests in the transaction are not excluded from the debtor’s estate. The resolution of these issues could be pivotal in determining an E&P debtor’s ability to restructure contractual agreements with production payment assignees.
Plugging and Abandonment Liability
Under state and federal law, E&P companies generally are obligated to plug and abandon a well after drilling or production ceases.10 Under federal law, oil and gas companies operating offshore on the Outer Continental Shelf, or OCS, are obligated to plug and remove all structures on a lease within one year of the end of production. The federal agency responsible for all Outer Continental Shelf oil and gas leasing, the Bureau of Ocean Energy Management, or BOEM, requires companies that do not meet a certain financial threshold to provide a surety bond that ensures funds are available for plugging and abandoning (P&A) wells and removal operations at the end of the lease in the event of bankruptcy. Working interest owners not deemed financially capable to acquire surety bonds may set up escrow accounts or acquire US Treasury bonds to meet their decommissioning liabilities. The BOEM determines the amount of that estimated P&A liability, and therefore the size of the bond required, in accordance with federal regulation. During periods of financial stress in the upstream sector, operators and working interest owners may be required to provide supplemental bonding, which at times can be quite significant. Accordingly, one of the major issues that often arises in bankruptcies involving E&P companies with offshore oil and gas leases is whether a P&A claim is entitled to administrative priority. A Fifth Circuit decision held that a P&A claim arising postpetition is entitled to administrative priority if the P&A liability accrued under state law, and interpreted the law of Texas in that regard.11 Nevertheless, debate remains over whether the court’s reasoning in that case was influenced by the Texas Railroad Commission’s finding that the wells created an imminent danger to the groundwater. Moreover, the decision did not reach the more nettlesome question of whether P&A liability arising prepetition should be treated as an administrative claim. At least one court has held that a claim for reimbursement of P&A expenses incurred postpetition was entitled to administrative expense status where the debtor’s P&A obligations arose prepetition.
Another layer of complexity arises in connection with the obligations of bonding companies who issue bonds to secure an E&P company’s P&A obligations. Some courts have held that, where a surety company makes payments to satisfy a debtor’s P&A obligations, the surety may be subrogated to the original obligor’s claim and priority for the amount funded.
Mineral Interests Owners’ Rights
By the time a chapter 11 case commences, E&P debtors often owe significant royalty payments to mineral interest owners, the lessor under their oil and gas leases. While a mineral interest owner’s prepetition royalty claim is typically afforded only unsecured status, a mineral interest owner may challenge this result based on special language in the owner’s lease, special relationships outside the lease, or statutory entitlements.
Leases may also include clauses allowing mineral interest owners to terminate a lease after non-payment of royalties. Notwithstanding the automatic stay under the Bankruptcy Code,12 such termination provisions are enforceable in some states, including Texas. To prevent termination, debtors often seek court approval to pay prepetition royalty payments under the theory that the loss of the valuable lease due to non-payment would harm the estate. While some bankruptcy courts may be willing to grant such relief, upon proper objection, some courts have found such payments to be impermissible outside of a chapter 11 plan. Further, numerous states have attempted to protect royalty owners by granting them statutory liens or other protections. For example, in Texas, royalty owners who sell oil and gas to a first purchaser may be entitled to a statutory lien,13 though the statute is especially detailed and often hinges on how the obligation to pay the purchase price to the royalty owner is construed.14 Louisiana state law provides additional protection by granting unpaid royalty owners the right to cancel leases for non-payment of royalties. Oftentimes, an analysis of the specific language contained in the lease and applicable law is required to determine the rights of non-debtor royalty owners.
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Oil and Gas Contractors’ Liens (M&M Liens)
In many jurisdictions oil and gas contractors receive statutory liens to secure payment for labor and services.15 Under Texas law, for example, the statutory lien attaches to the leasehold and related property and equipment (not to the production from the lease). Under Ohio law, a lien also attaches to the leasehold and related property and equipment, but the statute goes further to provide that, where there is no such lease or leasehold estate, the lien instead attaches to any mineral estate and oil and gas produced from the project (and the proceeds thereof).16 The Texas Supreme Court is not alone in acknowledging that the governing statutes are “very lengthy” and “not exactly a model of clarity.”17 A number of complicated issues arise under the state statutes, particularly related to the competition between M&M liens and blanket mortgages or other senior liens. For security interests arising from financing, a bank or other senior lienholder’s priority will be determined by the date of filing of the mortgage in the applicable jurisdiction. In contrast, under Texas and Ohio law, mineral liens relate back to the date of the first work performed. In addition, a contractor typically only has a lien on the specific properties on which the contractor performed labor, whereas the bank or other senior lienholder will likely have blanket liens on all the E&P company’s property. Accordingly, disputes surrounding the allocation of the debt among each property and the equitable concept of marshaling may arise.
State laws governing M&M liens are often detailed and require strict compliance with specific steps to create and preserve the contractor’s lien. For example, under Ohio law, a contractor’s lien may extend to oil or gas or the proceeds thereof, but the lien is not effective against any purchaser or pipeline carrier of such oil or gas until an affidavit is delivered to such purchaser or pipeline carrier by certified mail.18 Such nuances demonstrate how important it is for parties involved in E&P bankruptcies to understand fully the complexities of applicable state law.
Joint Operating Agreements Under the Bankruptcy Code
Joint operating agreements, or JOAs, are common in the oil and gas industry, allowing for multiple co-owners to cooperate in the exploration, development, and production of oil and gas in certain described property under the direction of a single operator. A JOA typically governs the relationship among working interest co-owners who own undivided fractional oil and gas leasehold interests and the operator, which is often simply the investor with the largest working interest. A JOA may also cover their relationships with owners who are not party to an oil and gas lease, and participate only as royalty owners. The JOA will, among other purposes, identify the property interests of the parties in the leases and property, commit the parties to participate in operations on the contract area (and provide procedures for resolving disputes), provide for sharing expenses and allocating liability with respect to joint operations, and control the rights of the parties in the production from the contract area.
As executory contracts under Section 365 of the Bankruptcy Code, JOAs are subject to rejection by debtors, however, significant issues often arise with respect to the parties’ rights under a JOA once the debtor has commenced a chapter 11 proceeding but has not yet assumed or rejected the JOA. The Supreme Court has held that during this time period, an executory contract is enforceable only by the debtor and not against the debtor. However, in the event the debtor chooses to continue to receive benefits from a counterparty prior to assuming or rejecting the executory contract, the debtor is obligated to pay for the reasonable value of those services which, depending on the circumstances, may be what is specified in the contract.19
Where the operator under the JOA files for bankruptcy, the operator may be deemed to have resigned under the terms of the JOA. However, because such a change in the debtor operator’s rights may violate the automatic stay,20 JOAs will commonly provide that in the event of the operator’s bankruptcy, the operator and the non-operators will form an interim operating committee that will control operations until the debtor elects either to accept or reject the JOA. Additional issues may also come into play where a debtor is a non-operator, particularly when the debtor has continued to accept performance under the JOA postpetition but later determines to reject the JOA. Typically, the rights of the parties during the interim period would be subject to the automatic stay, and after rejection, the non-debtor counterparty receives a general unsecured damages claim for breach of contract. However, this result becomes less certain in some situations. For example, while the costs of operations are typically shared by each of the parties to a JOA, commonly a JOA will allow a non-operator to withhold consent to particular drilling projects, thereby avoiding the obligation to contribute to the costs and forgo the production proceeds of that particular well. What happens, then, if a non-debtor operator proposes a
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drilling operation, the debtor elects “non-consent,” and the debtor later rejects the JOA? In this case, parties may have an opportunity to litigate whether the debtor’s interest — which had gone into “non-consent status” — would remain fixed in such status, or if the rejection of the JOA would take the interest out of “non-consent status.” These issues may affect recoveries of the debtor’s creditors who have security interests in its contractual rights.
The issues outlined above represent a small portion of the unique challenges E&P chapter 11 cases can present. State law considerations and the conflicting authority in various jurisdictions will generally render the restructuring of companies in the E&P industry more fact-specific than in other industries. E&P companies considering filing for protection under chapter 11, and those engaged in business with them as well as their lenders, would be wise to consider the implications of each of these issues when formulating their overall restructuring strategy.
If you have questions about this Buy Side Brief, please contact one of the authors listed below or the Latham lawyer with whom you normally consult:
J. Michael Chambers
Jeffrey S. Muñoz
Mitchell A. Seider
Keith A. Simon
Sean T. Wheeler
Adam J. Goldberg
David A. Hammerman
Annemarie V. Reilly
Sean H. McMahon
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1 In re ATP Oil & Gas Corp., No. 12-3443, 2014 Bankr. LEXIS 33 (Bankr. S.D. Tex. Jan. 6, 2014).
2 La. Land & Explor. Co. v. Donnelly, 394 F.2d 273, 277 (5th Cir. 1968).
3 11 U.S.C. § 541(b)(4)(B).
4 See 11 U.S.C. § 101(42A) and (56A), respectively, for the definitions of “production payment” and “term overriding royalty.”
5 11 U.S.C. § 541(b)(4)(B).
6 In addition, disputes have arisen over whether certain “production payments” should instead be recharacterized as loans and, therefore, excluded from the safe harbor under Section 541(b)(4)(B) of the Bankruptcy Code.
7 ATP Oil & Gas Corp., 2014 Bankr. LEXIS at *18.
8 Id. at *6.
9 The bankruptcy court held that summary judgment would only be appropriate where the economic substance of the transaction was (i) entirely consistent with an ORRI under Louisiana law and (ii) at least inconsistent in one respect with a loan under Louisiana law. Id. at *8.
10 The operator, the co-owners, and any predecessor owner may each be obligated to pay P&A costs and, in the event one party pays, the other parties may be entitled to indemnification or contribution. Accordingly, parties involved in E&P bankruptcy cases will need to consider who is the proper claimant and whether any other parties will be liable for P&A obligations. See, e.g., 16 TEX. ADMIN. CODE § 3.14(a)(1) (2007).
11 State v. Lowe (In re H.L.S. Energy Co., Inc.), 151 F.3d 434 (5th Cir. 1998).
12 See 11 U.S.C. § 362.
13 TEX. BUS. & COM. CODE ANN. § 9.343. With respect to lands leased from the State of Texas, Section 52.136 of the Texas Natural Resources Code provides the State with a lien securing payment of royalties. TEX. NAT. RES. CODE ANN. § 52.136(a).
14 For example, due to the fact that a royalty owner of oil production is typically given a right to a percentage of the oil produced, the owner is often considered a “seller” and, therefore, a lienholder under the Texas statute. Royalty owners of gas production, who are more commonly paid in cash, are not. The specific language of the lease must be considered in order to determine the royalty owners’ rights.
15 TEX. PROP. CODE ANN. § 56; OHIO REV. CODE § 13.021. Section 56 of the Texas Property Code incorporates the provisions of mechanic’s and materialmen’s liens under chapter 53 of the Texas Property Code for the purposes of enforcement.
16 OHIO REV. CODE § 13.021(A).
17 First Nat’l Bank in Graham v. Sledge, 653 S.W.2d 283, 285-86 (Tex. 1983).
18 OHIO REV. CODE § 13.021(B).
19 NLRB v. Bildisco & Bildisco, 465 U.S. 513, 531 (1984).
20 The automatic stay may also prohibit a non-operator from exercising remedies under the JOA or from exercising its right to set off amounts owed to the operator against amounts owed to the non-operator.