PROPERTY RIGHTS

In many situations, property rights are easily determined. Boundaries to stationary, observable assets such as land can be defined and enforced clearly. Property rights to crude oil and natural gas are far more troublesome, for two reasons. Both resources lie below the surface, making it difficult to locate the exact limits of the deposits, and they migrate within subsurface reservoirs. Some reservoirs cover many square miles, including hundreds of property owners, each with a competing claim to the oil and gas. Moreover, other reservoirs straddle national boundaries, encouraging international competition for the oil and gas. For these reasons energy production from crude oil and natural gas can involve serious common-pool losses. Although there is much to be gained from cooperation among property owners to avoid these losses, reaching a cooperative solution can be very difficult.

The problems of the common pool were most dramatically illustrated in Garrett Hardin's famous 1968 article "The Tragedy of the Commons." Exploitation of valuable resources when property rights are absent or poorly defined can be extremely wasteful. Because the parties must capture the resource before it is appropriated by another, time horizons become distorted, with undue emphasis on short-term production and neglect of long-term investment. Even if the trend of market prices indicates that resource values would be greater from future, rather than current, use, production will not be postponed. The losses are compounded by excessive capital investment in extraction and storage.

Common-pool problems characterize many resources where it is difficult to define property rights to restrain access and use. In North America, common-pool conditions in oil and natural gas production are created when firms compete for hydrocarbons in the same formation under the common-law rule of capture (which also governs fisheries and many other natural resources).

Under the rule of capture, ownership is secured only upon extraction. In the United States, production rights are granted to firms through leases from those who hold the mineral rights, typically surface land owners. Each of the producing firms has an incentive to maximize the economic value of its leases rather than that of the reservoir as a whole. Firms competitively drill and drain, including the oil of their neighbors, to increase their private returns, even though these actions can involve excessive investment in wells, pipelines, and surface storage, higher production costs, and lower overall oil recovery.

Oil production requires pressure from compressed gas or water to expel oil to the surface. There are three main types of reservoir drives to flush oil to wells: dissolved gas drive, gas-cap drive, and water drive. With a gas drive, the oil in the reservoir is saturated with dissolved gas. As pressures fall with oil production, the gas escapes from solution, expands, and propels oil to the surface. Hence it is important to control gas production so it remains available to remove the oil. With a gas-cap drive, the upper part of the reservoir is filled with gas, and oil lies beneath it. As oil is withdrawn, the compressed gas expands downward, pushing oil to the well bore. As with a dissolved gas drive, gas production from the gas cap should be restricted to maintain reservoir pressure to expel the oil. Finally, with a water drive, the oil lies above a layer of water. The compressed water migrates into the oil zone as the oil moves to the well and helps to push it from the rock formation. High oil recovery rates require that subterranean water pressures be maintained.

Maximizing the value of the reservoir requires that full reservoir dynamics be considered in drilling wells and in extracting oil. Gas and water must be recycled through the strategic placement of injection wells; wells with high gas-oil or water-oil ratios must be closed or not drilled; and the rate of oil production must be controlled to maintain underground pressure.

Each reservoir generally has a dominant drive, an optimal pattern of well locations, and a maximum efficient rate of production (MER), which, if exceeded, would lead to an avoidable loss of ultimate oil recovery. Unfortunately, oil, gas, and water are not evenly distributed within the reservoir. With multiple leases above the reservoir, some lease owners will have more oil, gas, or water than will others, and coordination among competing firms in well placement and in controlling production rates is difficult. Efficient production of the reservoir suggests that some leases not be produced at all. Further, since each firm's production inflicts external costs on the other firms on the formation, some mechanism must be found to internalize those costs in production decisions.

Maintaining subsurface pressures; effectively placing wells; coordinating timely investment; and controlling oil production across leases while protecting the interests of the various lease owners under conditions of geologic and market uncertainty are formidable challenges. Yet, if they are not adopted, common-pool losses are likely.

Common-pool problems in oil and gas have been observed since commercial production began in the United States in 1859. The solution, unitization, also has been understood for a long time. With unitization, a single firm, often with the largest leased area, is designated as the unit operator to develop the reservoir, ignoring lease boundaries. With unitization, optimal well placement and production are possible as is coordination in other activities to increase overall recovery from the reservoir; These activities include pressure maintenance; secondary recovery; and enhanced oil recovery (EOR), whereby heat, carbon dioxide, or other chemicals are injected into the reservoir.

All lease owners share in the net returns of unitized production, based on negotiated formulas. As residual profit claimants, the lease owners now have incentives to develop the reservoir (rather than the lease) in a manner that maximizes its economic value over time. When producers expect unitization to occur, exploration is encouraged because greater recovery rates and reduced costs are anticipated. Bonuses and royalties to landowners are higher because the present value of the oil and gas resource is greater with unitization.

Despite its attractions for reducing common-pool losses, use of unitization has been more limited than one would expect. Joe Bain (1947, p. 29) noted: "It is difficult to understand why in the United States, even admitting all obstacles of law and tradition, not more than a dozen pools are 100 percent unitized (out of some 3,000) and only 185 have even partial unitization." Similarly, in 1985 Wiggins and Libecap reported that as late as 1975, only 38 percent of Oklahoma production and 20 percent of Texas production came from field-wide units.

To be successful, a unit agreement must align the incentives of the oil-producing firms over the life of the contract to maximize the economic value of the reservoir without repeated renegotiation. Unit contracts involve a number of difficult issues that have to be addressed by negotiators. Because remaining production often lasts twenty years or more, unit agreements must be long-term and be responsive to considerable uncertainty over future market and geological conditions. They must allocate unit production and costs among the many firms that otherwise would be producing from the reservoir. Additionally, they must authorize investments that may be made later to expand reservoir production, and distribute the ensuing costs among the individual parties.

These are formidable tasks for unit negotiators. The negotiating parties must agree to a sharing rule or participation formula for the allocation of costs and revenues from production. There may be different sharing rules for different phases of unit production, such as primary and secondary production, and the rules should apply to all firms on the reservoir. This arrangement is termed a single participating area. There should not be separate participating areas for oil and gas; otherwise, different incentives for oil and gas production will emerge. Development, capital, and operating costs must be allocated in proportion to revenue shares in an effort to align all interests to maximize the economic value of the reservoir. In that case, each party will share in the net returns from production and hence will have an incentive to minimize development and production costs and to maximize revenues. Further, a single unit operator must be selected to develop the field. Multiple unit operators lead to conflicting objectives and hinder the coordinated production practices necessary to maximize the value of the reservoir. Supervision of the unit operator by the other interests must be determined, with voting based on unit participation.

All of these issues can be contentious, but reaching agreement on the revenue sharing or participation formula is the most difficult. Shares are based on estimates of each firm's contribution to the unit. Those firms with leases that reflect a natural structural advantage (e.g., more resources or easier access to resources) seek to retain this advantage in the unitization formula. Such firms are unlikely to agree to a unitization agreement that does not give them at least as much oil or gas as they would receive by not unitizing. Even if the increase in ultimate recovery from unitization is so great that these parties will receive more from unit operations than from individual development, they have a much stronger bargaining position in negotiations than less-favored tract owners. The former can hold out for the most favorable allocation formula, secure in the knowledge that the regional migration of oil will continue toward their tracts during any delay in negotiations. Indeed, holding out may increase the value of a structurally advantageous location. If the firms form a subunit without the participation of the owners of better-located tracts, the pressure maintenance operations of the unit may increase the amount of oil migration toward the unsigned tracts. The holdouts, then, benefit from the unit without incurring any costs of the pressure maintenance activity.

The information available to the negotiating parties for determining lease values depends upon the stage of production. During exploration, all leases are relatively homogeneous, and unitization agreements can be comparatively easy to reach using simple allocation formulas, often based on surface acreage. Information problems and distributional concerns, however, arise with development as lease differences emerge. Because reservoirs are not uniform, the information released from a well is descriptive of only the immediate vicinity. There will be disagreements over how to evaluate this information in setting lease values. As a result of disagreements over subsurface parameters, unit negotiations often must focus on a small set of variables that can be objectively measured, such as cumulative output or wells per acre. These objective measures, however, may be poor indicators of lease value.

Conflicts over lease values and unit shares generally continue until late in the life of a reservoir. As primary production nears zero, accumulated information causes public and private lease value estimates to converge, so that a consensus on share values is possible. Without unit agreement, secondary production from all leases may be quite limited. The timing of a consensus on lease values, however, suggests that voluntary unit agreements are more likely to be reached only after most of the common-pool losses have been inflicted on the reservoir.

Reaching agreement on these issues is a complex process. In a detailed examination of seven units in Texas, Wiggins and Libecap showed in 1985 that negotiations took four to nine years before agreements could be reached. Moreover, in five of the seven cases, the area in the final unit was less than that involved in early negotiations. As some firms became frustrated, they dropped out to form subunits, which led to a partitioning of the field and the drilling of additional wells but generally did not minimize common-pool losses. For example, 28 subunits, ranging from 80 to 4,918 acres, were established on the 71,000-acre Slaughter field in West Texas. To prevent migration of oil across subunit boundaries, some 427 offsetting water injection wells were sunk along each subunit boundary, adding capital costs of $156 million.

Other costs from incomplete unitization are shown on Prudhoe Bay, North America's largest oil and gas field, which was first unitized in 1977. Two unit operators, separate sharing formulas for oil and gas interests, and a disparity between revenue sharing and cost sharing among the working interests have resulted in protracted and costly conflicts. The parties on the field do not have joint incentives to maximize the economic value of the reservoir, but rather seek to maximize the values of their individual oil or gas holdings. Because ownership of oil and gas in Prudhoe Bay is very skewed, with some firms holding mostly oil in the oil rim and others holding mostly natural gas in the gas cap, the firms have been unable to agree to a complete, reservoirwide agreement. Disputes have centered on investment and whether natural gas should be reinjected to raise oil production, or liquefied and sold as natural-gas liquids. In 1999 Libecap and Smith showed that skewed ownership in the presence of gas caps characterizes other incomplete unit agreements elsewhere in North America.

Most states, as well as the U.S. government, have some type of compulsory unitization rule to limit the ability of a minority of holdouts to block a unit. Mandatory unitization began in the United States in Louisiana, in 1940. Due to political opposition by small firms that receive regulatory-related benefits, Texas, surprisingly, has not had a compulsory unitization law. Texas court rulings have tended to restrict unitization.

Although unitization is most problematical in North America, where there generally are more operators on a given oil field, the problems of coordinated production to avoid common-pool losses exist elsewhere. In the North Sea, Argentina, Ecuador, and the Caspian Sea, lease and national boundaries often do not coincide with reservoir boundaries. Under these conditions a nation may engage in competitive drilling to drain the oil and gas before its neighbor does. This incentive appears to explain the initial pattern of Norwegian drilling only along its boundaries with the United Kingdom (Hollick and Cooper, 1997).

Gary D. Libecap

See also: Governmental Approaches to Energy Regulation; Government Intervention in Energy Markets; Oil and Gas, Drilling for; Oil and Gas, Exploration for; Oil and Gas, Production of; Pipelines.

BIBLIOGRAPHY

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