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By: Ira L. Herman, Thompson & Knight LLP
The price of crude oil, like the price of virtually all commodities, moves up in times of high demand and down in times of excess capacity. When a mismatch exists between supply and demand, the markets are expected to self-correct. Excess supply should result in price and production cuts, while excess demand should be met with price and production increases.
DESPITE THESE TRUISMS, THE PRICE OF CRUDE OIL HAS continued its steady and protracted drop. In 2015, no fewer than 42 North American oil and gas producers filed for bankruptcy relief. The combined debt of these companies is $17.85 billion, split about 50.4% secured to 49.6% unsecured debt. History informs us that the price for a barrel of crude oil will stabilize and prices will recover. The big question is, when will this happen? Whenever it does, it may be too late for many financially distressed industry participants, especially considering the expectation, as widely reported in the press, that there will be more bankruptcy filings by oil and gas producers and more debt unloaded in 2016 compared to 2015.
The oil and gas industry is generally said to be divided into three segments: upstream, midstream, and downstream. The upstream segment includes companies that engage in the exploration for and production (E&P) of oil and gas. Businesses in the upstream sector find and produce crude oil, natural gas, and shale gas. To find and produce hydrocarbons, upstream companies require machinery, equipment, exploration services, and geophysical services. Collectively, the providers of these goods and services are known in the business as “oil field service providers.”
The midstream sector processes, stores, and engages in the wholesale marketing of hydrocarbons, including crude oil and natural gas and gas liquids. Transportation companies in this sector include pipeline companies, rail car operators, barge operators, oil tanker owners, and trucking companies. Storage may include tank farms and the like.
Oil and gas operations that take place after the production phase through to the point of sale are said to be downstream. Downstream operations can include refining crude oil and distributing the by-products down to the retail level. By-products include gasoline, natural gas liquids, diesel, and a variety of other energy sources.
During a run-up in commodity prices, upstream companies increased E&P efforts, resulting in strong demand for machinery and equipment. Businesses in the machinery and equipment space include manufacturers of oil and gas field machinery and equipment such as rigs, pipes, casings, etc. Weaker commodity prices have led to a sharp downturn in energy exploration and production, hurting these companies as domestic producers reduce costs to preserve cash and protect their balance sheets.
Businesses in the oil and gas field services industry primarily provide services to oil and gas producers (upstream companies), including drilling oil and gas wells; surveying wells; running, cutting, and pulling casings; chemically treating wells; and disposing of wastewater and other production waste. Consequently, demand for such services is highly dependent on oil and gas prices. Rising oil and gas prices typically result in increased demand for oil field industry services. The number of oil and gas drilling contracts generally rise with prices because previously unprofitable sites will become profitable and, therefore, more attractive to producers. In contrast, demand for oil services falls when oil and gas prices are low.
The failure of the markets to self-correct and rebalance supply with demand to stabilize crude oil prices in 2015 and 2016 (so far) has been blamed on the confluence of a number of obvious and less obvious domestic and international economic and geopolitical drivers. According to Louis Besland, head of the Europe, Middle East, and Africa oil and gas practice at AlixPartners Management Consultants, the oversupply in early January 2016 was around two million barrels a day. “This imbalance has been mainly created by the North American shale oil and gas in the past four or five years. That’s why Saudi Arabia believed from the beginning it’s not up to them to cut back,” according to Besland.1
Similarly, producers, in North America and globally, have maintained or increased production to generate the revenue they believe they require to continue in business. Thus, historically low prices for crude oil have resulted in more production and not less, as market participants have tried to pump their way out of trouble. Due to these factors and others, production remained at near historic highs through early 2016, despite the existing excess supply available to the markets.
On a global level, the challenges from the supply side of the ledger are reflected, by way of example, by the failure of the Organization of Petroleum Exporting Countries (OPEC) to agree on production limits at its December 2015 meeting amid Iran’s plans to boost exports following the end of international anctions affecting the Iranian oil industry. In mid-January, once sanctions were officially lifted, worries about Iran’s return to an already oversupplied oil market drove the price of Brent crude and of West Texas Intermediate to below $30 a barrel, their lowest levels since 2003.
From the demand side, the picture is also not pretty. In its January 2016 report, the International Energy Agency (IEA) trimmed its 2016 estimates for global oil demand, as China’s economic expansion appears to have continued to weaken. Consumption growth globally, according to the IEA report, will slow in 2016 to 1.2 million barrels a day, or 1.3%, from 1.7 million a day in 2015. “However,” says Tom McNulty, a Director at Navigant Capital Advisors, “the supply overhang is just under 2%, and in the 1980s the supply overhang was 15%. Today, it will take very little to soak up the excess, such as a good demand number from China or a missile launched in the Middle East.”
The downturn in oil prices hit projects all around the world; Wood Mackenzie, the global energy consulting company, says that 68 major projects were scrapped in 2015, which account for around 27 billion barrels of crude oil and natural gas. The Financial Times has estimated that some $1 trillion in planned production projects are likely to be cancelled. Already, countries like Saudi Arabia, Venezuela, and Russia, which rely heavily on state-owned producers of oil and gas for revenue, have suffered the consequences of the drop in these commodity prices.
Fundamentally, E&P is a capital intensive business. The equipment needed is expensive and not all wells drilled are economically viable. As a result, E&P companies must raise large amounts of capital in order to turn a promising hydrocarbon discovery into a producing asset. One obvious way to cover the costs of exploration is to use the revenue generated by existing production. Alternatively (or in the absence of an income stream generated by production), industry participants have divided producing assets into numerous fragments, all capable of being monetized to fund E&P. Finally, an E&P company may fund its capital needs by borrowing from an institutional or other lender, often pursuant to a reserve-based revolving credit facility.
A mineral rights owner is one who owns oil and gas deposits under the surface, including the right to explore, drill, and produce those deposits. However, many mineral interest owners are not in the business of exploration and production, as they lack the expertise and capital to explore and produce.
In order to monetize that interest, the mineral interest owner typically signs an oil and gas lease with an E&P company, giving the E&P company the right to explore and develop the subsurface in exchange for the obligation to pay the mineral rights owner a non-cost-bearing share of the income from the production, which is known as a royalty interest. As a royalty interest holder, the mineral rights owner is entitled to a stated portion of the gross production, if any, but has no right to enter the land and extract minerals, but also does not share in any of the exploration and development costs.
By virtue of the execution of the oil and gas lease, the E&P company becomes the 100% working interest owner and also obtains royalty interest in the amount conveyed by the mineral interest owner under the oil and gas lease. In contrast to a royalty interest, a working interest holder will have the right to explore and develop the minerals along with the obligation to pay the costs associated with exploration and development. A working interest in a property does not exist in perpetuity but is governed by the terms of the oil and gas lease. There may be a number of reasons for termination, including: (a) the failure to meet specified minimum production requirements, (b) the end of the productive life of a well, and (c) an agreement by the parties to terminate on a certain date.
The working interest holder may use portions of its interest to finance production, either by selling part of its working interest to third parties, using a fractional part of its net revenue as collateral for a loan, or by selling a portion of the income to be generated by production in connection with the working interest. An example of such an interest is the overriding royalty interest (ORRI). Unlike a landowner’s royalty interest, ORRIs are typically carved out from a working interest. As a general proposition, there are two types of ORRIs: (a) the perpetual ORRI, which lasts for the life of the lease between the working interest holder and the mineral rights holder, and (b) the term ORRI, which is limited in duration, either until a specified volume of production is reached or a stated value of production is reached. Similar to ORRIs are net profit interests (NPIs). An NPI is carved out of a working interest, much like an ORRI; however, the NPI holder is only paid out of the profits earned from production over a contractually agreed-upon time span (in other words, ORRIs are paid as a percentage of gross revenue/production and NPIs out of net profits).
Joint operating agreements (JOAs) are common in the oil and gas industry because they allow multiple coowners 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 coowners, who own undivided fractional oil and gas leasehold interests, and the operator, who is often simply the investor with the largest working interest. The JOA will, among other purposes, identify the 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 allocate liability with respect to joint operations, and control the rights of the parties in the production from the contract area.
Another type of agreement typical in the oil and gas industry is the farmout agreement. Farmouts are often used when a lease is expiring and the lessor does not have capital to drill. Although farmouts can take a myriad of forms, a farmout agreement typically provides for a working interest owner to assign a working interest to a party known as a farmee in exchange for certain contractually agreed-upon services. Typically, these services include drilling a well in a certain location to a certain depth within a specified timeframe. After the contractually agreed-upon services have been completed, the farmee is said to have earned an assignment, subject to the reservation of an overriding royalty interest in favor of the working interest owner.
This overriding royalty interest is usually said to be a convertible override. This means that upon payout, which is the point where the drilling costs have been recouped from production from the well, the farmee can elect to convert this override into a portion of the working interest. The decision whether to convert or not depends on whether the farmee wishes to join in production costs in exchange for the possibility of a larger return. When a farmee is comfortable with the project costs and production from the well it has drilled, the farmee will generally convert its override interest into a working interest.
Farmout agreements tend to be highly negotiated documents, although they also generally include standard terminology, as the provisions of all farmout agreements generally address several crucial issues. These issues include the duty imposed (i.e., whether the farmee has an obligation or an option to drill, etc.), the obligation that must be met in order for the farmee to earn its target interest in the property, the interest in the property to be earned, the number of wells to be committed to the farmout agreement (can be one or more), and the timing of issuance of the assignment of farmout acreage to the farmee (generally after completion of the farmee’s obligations to drill, etc.).
An E&P company can rely on a reserve-based revolving credit facility (an RBL facility) for its working capital needs and to fund its exploration and development programs. However, this type of financing is only available where revenue is already being generated by prior production. Loan availability under an RBL facility is permitted pursuant to a borrowing base formula set by the lender to the industry participant, primarily in consideration of the value of the participant’s proved oil and gas reserves. The value of such reserves is determined by reference to a price deck set by the lender, under the terms of the RBL lending agreement.
Although RBL facilities typically require a lender to consider the value of the borrower’s proved reserves in setting the borrowing base, an RBL lender is generally also permitted to consider such other information as it deems appropriate at its sole discretion. In short, the borrowing base is whatever the lender says it is.
RBL facilities typically require scheduled redeterminations of the borrowing base on a semi-annual basis, once in the spring and once in the fall. Additionally, a lender is generally provided the right to a single special redetermination between scheduled redeterminations. Finally, incurring additional long-term debt often triggers automatic reductions to the borrowing base (often a $0.25 reduction for each $1.00 of additional debt incurred), and the RBL lender is often permitted a special redetermination in connection with any termination of commodity hedging contracts. Despite the forgoing, says McNulty, “it is important to understand that there are many lending facilities in the market now that service their debt payments, even as the asset valuation falls below credit thresholds.”
In times of steep declines in commodity prices, many E&P companies will find the availability for additional borrowings under an RBL facility reduced, in some instances, to a level below the aggregate 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 at least to 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 lender as collateral, which leaves the borrower with the sole option of paying down the debt. Choosing to repay a deficiency amount in installments gives the borrower a short window of time to raise capital, including by selling properties or securing additional credit through a junior lien or subordinated debt, in order to avoid an event of default under its RBL facility. An impending RBL default is one of many reasons an E&P company may seek bankruptcy relief. A more complete discussion of the treatment of RBL facilities in a bankruptcy case is beyond the scope of this article. The discussion that follows addresses the impact of bankruptcy on several of the types of agreements E&P companies use to raise capital, including, by way of example, oil and gas leases and joint operating agreements.
The status of rights under oil and gas agreements, including oil and gas leases and joint operating agreements, can be affected by bankruptcy law. A few of the common issues that arise in oil and gas bankruptcy cases include the treatment of joint operating agreements, oil and gas leases, and farmout agreements. The treatment of oil and gas agreements under the Bankruptcy Code is dependent on the characterization of such agreements under state law. It is therefore crucial to be aware of how the mineral law of the applicable state characterizes your rights. For example, while joint operating agreements are almost always executory contracts, an oil and gas lease may, depending on the governing non-bankruptcy law, constitute either evidence of an interest in real property that is subject to assumption or rejection under section 365 of the Bankruptcy Code or an unexpired lease that is subject to assumption or rejection under section 365.
Despite employing the noun “lease” in its description, an oil and gas lease is not necessarily an unexpired lease subject to rejection in bankruptcy and may actually instead be a real property interest. The question of whether an oil and gas lease falls within the definition of either “executory contract” or “unexpired lease,” as those terms are used in section 365 of the Bankruptcy Code, is determined by referring to the applicable non-bankruptcy law.2 The 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 and is subject to assumption or rejection under section 365 of the Bankruptcy Code.3
If a lease is classified as a real property interest rather than as a lease, a debtor who is a lessor cannot reject the lease and thus deprive the lessee of its expected benefits under the lease. Although a lease that is classified as an executory contract or unexpired lease is subject to rejection, some recent case law has suggested that under section 365(h) of the Bankruptcy Code, which allows a lessee of an unexpired and already commenced lease of real property to retain its rights under the lease that are in or appurtenant to the real property for the balance of the term of the lease, “rejection would not appear to oust [lessees] from their rights to occupy the premises.”4
Although the parties cannot control whether a lease will be characterized as an executory contract or unexpired lease, a lessee can prepare for the risk of rejection in bankruptcy by crafting and defining its rights under the lease so that they will likely be found to be “in and appurtenant to the real property” under section 365(h).5
Joint operating agreements are uniformly held to be executory contracts and can thus be assumed or rejected under section 365 of the Bankruptcy Code.6 Like any rights created under an executory contract, a party’s rights under a joint operating agreement are at risk in the event of a bankruptcy filing. Although the risk of rejection cannot be entirely eviscerated, a party may mitigate that risk by (1) including a standard provision ensuring that the joint operating agreement is construed as an executory contract and providing for adequate assurance of performance; (2) filing a memorandum of the operating agreement of record to protect any contractual lien rights; (3) negotiating for and preserving offset and recoupment rights; and (4) drafting the operating agreement to protect certain rights as covenants running with the land, which are not subject to rejection in bankruptcy.
Traditional sources of capital may not be available to producers in calendar year 2016, due to the low price environment. As a result, producers will have to seek other answers to their financial problems, including by invoking the jurisdiction of the bankruptcy courts. By turning to the bankruptcy courts, producers may be able to obtain fresh credit not otherwise available to them and sell assets that may be difficult, if not impossible, to sell outside of a bankruptcy process. This is because the Bankruptcy Code provides capital providers, whether they are lenders or purchasers of distressed assets, with protections and benefits not available to them outside the bankruptcy courts. These protections and benefits, in turn, serve to enhance the ability of financially distressed businesses to dispose of assets and maximize value for existing stakeholders.
As mentioned at the outset, in calendar year 2015, no fewer than 42 North American oil and gas producers filed for bankruptcy relief. The combined debt of these companies is $17.85 billion, split about 50.4% secured to 49.6% unsecured debt. There is no reason to think, at this time, that there will be fewer filings in calendar year 2016 in the oil and gas space than there were in 2015, as bankruptcies are accelerating. Magnum Hunter Resources Corp., Swift Energy Co., and New Gulf Resources filed for Chapter 11 relief in December. In mid-January, The Wall Street Journal reported that “three major investment banks—Morgan Stanley, Goldman Sachs Group Inc., and Citigroup Inc.—now expect the price of oil to crash through the $30 threshold and into $20 territory in short order as a result of China’s slowdown, the U.S. dollar’s appreciation, and the fact that drillers from Houston to Riyadh won’t quit pumping despite the oil glut. As many as a third of American oil and gas producers could tip toward bankruptcy and restructuring by mid-2017, according to Wolfe Research. Survival, for some, would be possible if oil rebounded to at least $50, according to analysts.”7
With more assets hitting the market, bargain hunters may not be willing to pay top dollar when so many deals are available in the market place. We have already seen lenders expressing concern about the volume of assets hitting the market or likely to hit the market in the coming months. Moreover, there has been at least one instance where a lending group drove a sale process to a rapid completion for fear that competing assets would become available in the marketplace and further depress the value they could recover for the assets. “Valuation skills are essential, and they must be analytically sound. You cannot use one price curve or one flat deck for valuation purposes in a market this volatile,” says McNulty.
Any purchaser of distressed oil and gas assets must address certain risks endemic to distressed M&A transactions. First and foremost, such a purchaser must evaluate the fraudulent transfer risk created by the purchase of any assets at a bargain price. Fraudulent transfer risk refers to the ability of a court to look as far back as six years to find that a purchase price paid was less than “reasonably equivalent value” for the assets that were acquired, at a time when the seller was insolvent or in “financial distress” of the type listed in the applicable statutes.8 There are two significant elements that compose the fraudulent transfer risk. First, if there is a finding that there has been a fraudulent transfer, the purchaser of an asset may be forced to pay additional sums for an asset it thought it had purchased at an agreed upon (lower) price. Second, there is the cost of defending an action alleging the existence of a fraudulent transfer. Such defense costs can be substantial, especially in more complex cases. Sales of distressed businesses or their assets tend to be made under duress, at a time when a company may be insolvent, and involve assets for which potential buyers are wary of overpaying. Thus, such sales carry a heightened risk of being made for less than “reasonably equivalent value” and of the seller being found to have been insolvent at the time of sale.
Another risk associated with distressed M&A transactions is the risk that the seller will end up in a bankruptcy case after the signing of an agreement to sell to purchaser but prior to a closing of the sale transaction. This scenario subjects the purchaser to the risk that the now-bankrupt seller will exercise its rights under section 365 of the Bankruptcy Code to reject the sale agreement or attempt to renegotiate the terms of the sale by threatening rejection.9 Upon rejection, a seller will have no further obligations to perform under the agreement, and the purchaser will generally have an unsecured prepetition claim for the damages it incurs.
A third risk a purchaser has with respect to a distressed M&A transaction is that payments received by the purchaser post- closing but pre-filing of a bankruptcy, including true-up payments or purchase price adjustments, may be avoidable by the seller as preferential transfers under section 547 of the Bankruptcy Code, depending on timing.
In view of the considerable bankruptcy risk that exists with respect to distressed M&A transactions, purchasers have been reluctant to proceed in the ordinary course, i.e., entering into a sale agreement and closing on that agreement. Instead, purchasers have been requiring sellers of distressed assets, including oil and gas assets, to file for bankruptcy relief and obtain bankruptcy court approval of the proposed sale despite auction-related risk and the expense associated with a bankruptcy sale process. By doing so, not only does the purchaser mitigate much of the bankruptcy risk described above, but a sale pursuant to the applicable provisions of the Bankruptcy Code may afford the purchaser certain additional benefits available under the Bankruptcy Code.
There are two ways an entity can sell its business or substantially all of its assets in a bankruptcy case filed under Chapter 11 of the Bankruptcy Code. First, an entity can sell pursuant to a plan of reorganization. A plan of reorganization is essentially an agreement between a debtor entity and its stakeholders settling the claims of the stakeholders, using the value of the debtor or its assets to fund such settlement. The filing of a reorganization plan comes at the end of a case. More often than not, a Chapter 11 case can be complex, and it is not unusual for a case to last more than a year. Also, as is currently occurring with oil and gas, there is a continued risk during the pendency of a Chapter 11 case that asset values will continue to erode—the so-called melting ice cube.
The alternative to a Chapter 11 plan process is a section 363 sale. Traditionally, debtors used section 363 to sell discrete assets, specific business units, or subsidiaries. Unlike a plan of reorganization or a sale that occurs under a plan approved at the end of a case, a section 363 sale can occur at any time during the Chapter 11 process.
In 2015 and 2016, many of the Chapter 11 cases filed by E&P companies are being filed together with a motion to sell substantially all of such entities’ assets, pursuant to section 363 of the Bankruptcy Code. These section 363 cases tend to move quickly, which benefits both buyers of distressed assets and stakeholders that may have an interest in such assets. The speed of such cases benefits stakeholders by reducing the costs associated with operating a distressed business entity and benefits buyers by allowing them to gain control of the assets they are buying, with the blessing of a bankruptcy court, without the delay that a longer bankruptcy process might engender. In the current low price environment and due to the benefits to buyers and stakeholders alike, there is no reason to think there will be a slowdown any time soon in the filing of oil and gas section 363 cases.
Ira L. Herman is a partner in the Bankruptcy and Restructuring group at Thompson & Knight LLP.
RESEARCH PATH: Financial Restructuring & Bankruptcy > Identifying and Managing Bankruptcy Risk > Oil and Gas Agreements > Practice Notes > Transnational Energy Insolvency
For more information on Transnational Energy Insolvency, see
> DIRECTOR DUTIES IN A TRANSNATIONAL ENERGY INSOLVENCY
For more information on rights in oil and gas insolvency, see
> EXAMINING THE STATUS OF RIGHTS IN BANKRUPTCY ARISING UNDER OIL AND GAS AGREEMENTS, SPECIFICALLY JOINT OPERATING AGREEMENTS
RESEARCH PATH: Financial Restructuring & Bankruptcy > Identifying and Managing Bankruptcy Risk > Oil and Gas Agreements > Practice Notes > Oil and Gas Agreements
For more information on oil and gas leases in oil and gas insolvency, see
> EXPLORING THE STATUS OF RIGHTS IN BANKRUPTCY ARISING UNDER OIL AND GAS AGREEMENTS, SPECIFICALLY OIL AND GAS LEASES AND THE SAFE HARBOR PROVISION FOR FARMOUT AGREEMENTS
1. Claudia Carpenter, Saudi Oil Exports Climb to Seven-Month High, Bloomberg (Jan. 18, 2016),http://www.bloomberg.com/news/articles/2016-01-18/saudi-oil-exports-climb-to-seven-month-high-as-refineries-return. 2. Butner v. United States, 440 U.S. 48 (1979). 3. Terry Oilfield Supply Co. v. Am. Sec. Bank, 195 B.R. 66, 70 (S.D. Tex. 1996); Jacobs v. CNG Transmission Corp., 332 F. Supp. 2d 759, 772 (W.D. Pa. 2004). But see In re Powell, 482 B.R. 873, 878 (Bankr. M.D. Pa. 2012) (holding that an oil and gas lease is clearly a lease of real property within the bankruptcy definition). See also Chesapeake Appalachia, LLC v. Powell (In re Powell), 2015 U.S. Dist. LEXIS 152509 (M.D. Pa. Nov. 10, 2015). 4. Powell v. Anadarko E&P Co., L.P. (In re Powell), 482 B.R. 873, 2012 Bankr. LEXIS 4324 (Bankr. M.D. Pa., 2012). 5. In re Powell, 482 B.R. at 879. 6. In re Wilson, 69 B.R. 960, 963 (Bankr. N.D. Tex. 1987). 7. Bradley Olson & Erin Ailworth, Oil Plunge Sparks Bankruptcy Concerns, Wall st. J., Jan. 11, 2016. 8. For the elements of a fraudulent transfer under the Bankruptcy Code, see 11 U.S.C. § 548, as amended. Virtually every jurisdiction has a debtor and creditor law covering the avoidability of fraudulent transfers. See also 11 U.S.C. § 544, as amended, which imports such state law into the Bankruptcy Code. 9. Section 365 of the Bankruptcy Code provides that a trustee or debtor in possession can assume or reject (with exceptions) its “executory contracts” and “unexpired leases.” A sale agreement, after signing and prior to closing, would be subject to the provisions of section 365.