Understanding Production Sharing Contracts in Texas Oil and Gas

What is a Production Sharing Contract?

In the oil and gas industry, a PSA provides a structure for the sharing of net revenues from mineral production. A PSA must be understood in the context of its application to the various types of legal relationships that apply in the oil and gas industry. In Texas, "mining" concerns like oil and gas production refer to a legal relationship that allows the mineral owner to receive net revenues. Among its purposes, the PSA is a document that can supplement or amend, but cannot replace, conveying the minerals to third parties like lessees, working interest owners, royalties, overriding royalties and others. A PSA occurs when two or more parties contract to share net revenues from production. Generally , the parties contract with respect to the following matters: a) the type and amount of costs to be deducted from gross production sufficient to determine net revenues; b) the timing of revenue distributions following deductions; and c) the methodology used to determine quantities of production or of the costs to be deducted in calculating net revenues received by the parties. A PSA may also allocate various costs of production among the parties. The determination of, and distribution to, the parties of net revenues from gross production has both joint account forms of allocation and partitioning forms of allocation.

Main Elements of PSAs

The key components of a production sharing agreement include profit oil, cost recovery and revenue sharing terms. In short, the parties must first determine how to allocate the costs of exploration and development between the parties, and how much profit oil each party will receive.
Cost recovery typically involves an initial reimbursement of development costs up to a predetermined cap. Under a cost recovery scheme, the host government or state owned national oil company reimburses the parties for "cost" in the hope that as production commences, it will exceed the cap, allowing for a share of the excess production proceeds. Therefore, PSAs usually include a cost recovery provision seeking to reimburse costs up to the amount of investment by the host government. This can lead to disputes over what types of costs are allowable. While some countries allow wide latitude in the types of costs allowed, others impose strict limitations. The parties should carefully address these issues in connection with defining the type of costs that will be allowed and recoverable. Parties should also try to anticipate and address how unanticipated costs will be handled. In other words, if the actual construction cost exceeds the amount set forth in the PSA, how will the additional costs be recovered? And in connection with that, what happens if costs are lower than projected?
The cost recovery share is often defined in a cost recovery percentage – the parties agree that the host government will have the right to recover a certain percentage of the well stream until authorized costs are recovered. The parties then set forth a cap on the amount of recovered costs.
Once costs are recovered, the remaining revenues and the production are called "profit oil" and the parties must agree as to how the profit oil will be split. The profit oil share is frequently expressed as a sliding scale based on cumulative production amounts. For example, if there is limited production, the host government receives 60%, the contractor receives 40%; when production is above a designated threshold (e.g. 350,000 bbls), the host government receives 70%, the contractor 30%; when production is above a designated threshold (e.g. 1 million bbls), the host government receives 80%, the contractor 20%.
In addition to share of profit oil and cost recovery, the parties to a PSA need to address the allocation of other types of taxes and royalties. A royalty is a payment made by the contractor to the government for the extraction of minerals or hydrocarbons. Royalties may be levied on gross income or on production. Royalties usually apply to production from the outset, once a threshold production is reached or as the project progresses. In any case, royalties typically increase over time.
Contractors may get a reduced rate of production tax for a limited period of time. Production taxes may be renegotiated periodically or triggered by changes in the law, and may be subject to depreciation at accelerated rates.
Other taxes that may be applicable include value added tax (a tax on goods and services that is assessed at each stage of the supply chain), excise tax (a tax charged on the sale of a particular good, e.g. alcohol, tobacco, fuel, tires, fast food, etc.), stamp duty (a tax paid when passing certain documents, usually related to the transfer of real property or shares of stock), environmental control taxes, export/import duties, withholding taxes, and tariffs (a tax on goods that are exported out of or imported into a country).
A production sharing agreement may include an arbitration clause. The parties may choose to have the dispute resolved through binding arbitration in a specific location.

Legal Basis for PSAs in Texas Law

Unlike some other U.S. states, Texas does not have a specific statute governing production sharing agreements. However, the Texas Natural Resources Code’s prohibition against pooling and unitization of lands without the consent of royalty owners has led some commentators to conclude that under Texas law, production sharing agreements are perhaps a form of pooling and unitization requiring such consent. Alternatively, it is a form of pooling consent (although such consent can be inferred even in the absence of an express pooling clause in the oil and gas lease) to the grant of the production sharing agreement as if it were a pooling and unitization agreement.
Regardless of the legal basis for PSAs in Texas, creation of such agreements without landowners’ consent is fraught with obstacles. In Myers v. Gulf Coast Cement Corp., the Texas Supreme Court pointed out that pooling and unitization agreements create co-tenancies or cotenants in the oil and gas interests involved, which requires them to be executed by all who own the right of control over the leasing decision (i.e. owners of the working interest), or by at least one of them with the authority of the others.
Many, if not most, of the landowners whose leases are pooled pursuant to an invalid pooling and unitization agreement sue in an effort to have the offending document set aside. The validity of pooling and unitization agreements has been a real concern in the Texas courts since the 1950s.

Advantages of PSAs for Exploration Companies and Mineral Owners

Benefits for Oil Companies and Landowners of Production Sharing Agreements (PSAs)
For oil companies, the most obvious benefit of PSAs is risk mitigation. Doing business in the oil and gas industry is not for the faint of heart, and many projects are still shaking out from low commodity prices. Taking on some of the financial risks of exploration and production (E&P) can help companies directly manage their potential losses by attracting partners who take on some of the risk of failure in return for a fixed cut of production and/or revenue.
Some E&P deals also involve landowners who take an equity position in a company’s efforts to explore and exploit hydrocarbons on their own property. This encourages landowners to allow companies to come on their land and drill, because it gives them an incentive to look the other way when companies disturb their land with drilling rigs and other equipment. But landowners also get a financial boost from PSAs that might be even more lucrative than royalties and bonuses that they receive from traditional leases.
Through a PSA landowners receive a greater share of production than they would through a traditional lease, which in Texas is typically 25-30%. With typical royalty payments, landowners still need to wait for development and production to see a return on their investment. This process can take years and even decades, depending on the structure of the lease. PSAs are therefore beneficial from a cash flow perspective.
Because landowners do not participate in PSAs in a "working interest" capacity – which means they don’t share directly in the ultimate profits of the operation – this type of arrangement will allow them to reduce the amount of liability they assume for any drilling operations or the attractiveness of a "partners only" arrangement to their neighbor if the neighbor does not want to participate in the PSA.

Challenges and Risks Associated with PSAs

The challenge with a production sharing agreement is that the parties will share both the upside and the downside of every potential venture. The key is to understand and appreciate that risk from the outset. The ideal use of a PSA is with known reserves or proven reserves in the partnership. Indeed, the concept of using a PSA in connection with unknown reserves or wildcat wells is very risky and sometimes can be dangerous depending on the negotiation sophistication of the parties. Like most of these joint operating type agreements, how the PSA allocates risk to various events is critical, but it does not have to be 50-50. Indeed, the fundamental legal principle that goes to the problem with a PSA is that a PSA is more risk sharing than profit sharing. The fact of the matter is that if a price of oil or gas drops substantially, the parties are going to lose money, regardless of the existing arrangements. If they discover noncommercial amounts of oil or gas, the parties will split that noncommercial oil and gas.
The parties need to consider the effect of price fluctuations for the commodity. As an example, if a well is producing 500 MCF per day, but the price now is only $2 . 00 per MCF, yet the contract pricing provides the operator with $3.83 per MCF, whose favor does that arrangement operate? If this ownership interest has little value because of the market, would you still want the same arrangement? Can you modify this in some way? What happens if the price of oil jumps to $100.00 per barrel, but the parties’ share of the value drops due to this arrangement?
All of those are worthy considerations when drafting a PSA. Another problem can involve mandatory agency. A mandatory agency means that one of the parties will take on the role of an agent and automatically act on behalf of the other party. This exists when one of the parties holds title to legal interests created by the other, for example easements, oil and gas leases, etc., with the duty to hold under certain fiduciary duties, obligations to account, render reports, etc. This is very relationship-based and must be explained to the parties prior to proceeding.
A good production sharing arrangement will include many of the same provisions as a joint operating agreement, including the right to audit and require an operator to make deductions for dealing with the oil and gas operations.

Case Examples of PSAs Used in Texas

Examining real-world examples of production sharing agreements (PSAs) in Texas—both in the new play and older plays—can provide insight and demonstrate their potential. In 1993, Bridge Resources through its affiliate royalty interest owner New Frontier Resources entered into a PSA with Petro-Hunt covering a number of leases including the Eagleville Field in East Texas. The PSA required a $1.00 per Mcf payment to the royalty interest owner instead of the standard postproduction royalty percentage. The $1.00 per Mcf was below current market price which meant the royalty owner would be incentivized to get the gas into the pipeline so that it would not be stranded. The lower price on a per Mcf basis would help keep the new Eagleville wells viable while providing an enhanced return to the royalty owner which was a publicly traded company. The PSA covered 26.8 Bcfe of reserves and was expected to generate annual revenue of $20 million for the royalty owner. Today, however, the Eagleville Field is producing over 116 Bcfe and instances of well bleed risk have been minimized by the PSA. Additionally, as a result of the PSA the royalty owner had increase cash flow which enhanced their financial performance for year-end reporting while continuing to take a small percentage of the proceeds when the gas is sold at the higher, market rate. The PSA structure allowed the royalty owner to provide its investors a healthy return while maintaining access to upside potential. Another example is EOG’s recently announced joint venture with Yates Petroleum Corporation in Eddy County, New Mexico. Yates received an upfront payment of $125 million plus a carried interest on EOG’s drilling and completion costs on the first 5 horizontal wells on Yates’ 60,000 net acres. EOG’s cost for those wells is expected to be in the range of $8.5 – 9 million each which includes the land costs. If all 5 "averages" out to $8.7 million each then the total cost for EOG would be $43.5 million. Yates has accrued $3.5 million in land costs which gives EOG an approximate net cost of $40 million to drill 5 wells. If the 5th well is as good as well #1 then Yates’ royalty interest will be significant! The only concern thus far is the efficiency of EOG’s completion operations. Everyone was surprised to find such a big difference in lateral length and amount of proppant used in well #1 as compared to wells #2, #3, #4, #5. The jury will be in for several months but if Yates gets to share 30% of the production from multiple, long laterals with lots of proppant that will be a game changer for other lessors.

Emerging Trends Involving Oil and Gas Production Sharing Contracts

Looking ahead, the impact of technologies like 3D seismic mapping and artificial intelligence could change the risk-reward balance as well. If current advances in technology allow for more precise exploration and drilling efficiency, the cost to a producer may go down considerably. The associated risk of failure to find significant reserves could be minimized, making the rewards from share of profit more attractive under a PSA. On the regulatory front , federal deregulation of the oil and gas industry appears to be the order of the day. Any such shift in the trend would decrease the existing friction between states and the federal government over control of offshore leases. Since PSAs have traditionally been limited to offshore activities, such a change could open up additional avenues for their use at the state level, particularly in those areas where access to capital is constrained. The emergence of production sharing agreements in this manner would closely resemble the common unitization structures of operations in the industry, which have roots in landowner groupings and alliances formed around the common goal of extracting resources from a producing tract.