FISCAL META-MODELING—1
The manner in which the economic and system measures of a fiscal regime interact with exogenous and user-defined parameters is complex and complicated, and usually difficult to decipher and understand. The purpose of this article is to demonstrate the application of a "meta-modeling" approach to fiscal system analysis that provides a new way to think about the design and implementation of a fiscal regime.
In the meta-evaluation procedure, a cash flow model of a field governed under a specific fiscal system is used to generate meta-data that are developed into linearized functional relations describing the system. Meta-modeling is not a new idea, but as applied to fiscal system analysis and contract valuation is both novel and useful.
A constructive approach to fiscal system analysis is used to isolate variable interaction and determine the manner in which private and market uncertainty impact take and the economic measures associated with the development. To illustrate the method, the impact of royalty relief associated with the deepwater Na Kika development in the Gulf of Mexico (GOM) is examined.
The computational models and results described in this article are specific to the royalty/tax fiscal system under consideration and the derived cash flow estimates, but the analytic approach and methodology are readily generalizable to any concessionary or contractual system. Other publications1 2 contain a more complete exposition of the material in this article.
Focus of fiscal system analysis
The focus of fiscal system analysis depends upon your perspective.
From the host government's point of view, focus is usually maintained on the division of profit (take) between the contractor and government.3 4 From the operator's perspective, economic measures such as the present value and rate of return describing the expected profitability of the project are of primary interest.
A wide degree of uncertainty is inherent in the computation of any economic or system measure associated with a field, and the only time that take, present value, or rate of return can be calculated with certainty is after the field has been abandoned and all the relevant revenue and cost data made public. Only in the case of "perfect" information, when all revenue, cost, royalty, and tax flows are known for the life of the field can profitability and the division of profits be reliably established.
Unfortunately, because of the frequent divestments and joint venture/ farmout type arrangements that occur over the life cycle of a field, and particularly near the end of a field's life, complete economic profiles are almost never maintained, and it is rare indeed when the net cash flow from a real asset is available outside the firm.
Cash flow and cost information is proprietary. Operators on federal leases are required to report production data to the government on a well basis, and so the revenue and royalty stream at any level of aggregation can be readily estimated, but the revenue stream is only half of the equation; the all-important and ever-elusive cost data—including capital and operating expenditures, tangible and intangible splits, depreciation schedules, financing costs, interest on payments, decommissioning cost, etc.—all need to be inferred. The reliability of the inference represents one of the primary limitations associated with an accurate computation of the economic and system measures associated with a field.
Sources of uncertainty
The computation of economic and system measures requires each of the revenue and expense items to be estimated and forecast over the life of the project under conditions expected to occur in the future.
Imperfect information, incomplete knowledge, and private/market uncertainty dictate the terms of the correspondence. The manner in which these forecasts are performed, relying on both art and science, opinion and fact, rules-of-thumb and advanced modeling, depends critically on the assumptions of the user.
Most of the relevant economic conditions of a fiscal regime, regardless of its complexity, can be modeled, and thus the sophistication of the contract terms themselves usually do not represent an impediment to the analysis. The uncertainty is elsewhere: geologic uncertainty, production uncertainty, price and cost uncertainty, investment uncertainty, technological uncertainty, market uncertainty, private uncertainty, and strategic uncertainty.
A detailed and realistic field description is the first and most important estimate to be made.
The size, shape, productive zones, fault blocks, drive mechanisms, etc., of the reservoir must be estimated with as much accuracy as possible since they determine the capacity of the structure, the required number and location of wells, and the supporting infrastructure requirements.
Estimates of production rates are based on geologic conditions at the reservoir level, decline curve analysis or similar techniques. Hydrocarbon price, development cost, technological improvements, and demand-supply relations impact the revenue of a lease and investment planning.
If the terms of the contract are subject to negotiation, the final contract terms may not be observable. Strategic objectives of a corporation are generally difficult to quantify and can vary dramatically over time.
The types of estimates that can be performed depend on the stage of development of the project and the design and planning information available. Initial cost and production estimates typically fall between "order-of-magnitude" estimates (on the order of 25-50% accuracy) and "conceptual development plan" estimates (on the order of 15-25% accuracy).
Rule-of-thumb estimates are, in most cases, only an approximation of the order-of-magnitude of cost and are useful for quick "ball-park" estimates. Many assumptions are implicit in rule-of-thumb factors, and the average deviation from actual practice can often be 50% or more.
The uncertainty associated with the value of the system measures will almost always fall within a broad range, and in the worst case, the range itself may be unknown.
Concessionary systems
Governments decide whether resources are privately owned or whether they are state property.
Under a concessionary system (also referred to as a royalty/tax system), the government or land owner will transfer title of the minerals to the oil company which is then subject to the payment of royalties and taxes. The royalty and tax rates are normally specified in the country or state's legislation (and are thus transparent) and are the same for all companies (no negotiations involved).
The fiscal terms of royalty/tax systems are not necessarily "fixed," however, because governments frequently change their petroleum laws and taxation levels, and in some instance, the terms of a royalty/tax system may be subject to negotiation. Sliding scale features and various levels of taxation may exist peculiar to one country or another,5 6 7 but most royalty/tax systems are fairly straightforward to understand.
Fiscal components of concessionary systems
The concession was the first system used in world petroleum arrangements and can be traced to silver mining operations in Greece as early as 500 BC.
The first petroleum concessionary agreements consisted only of a royalty. As governments gained experience and bargaining power, contracts were renegotiated, royalties increased, and various levels of taxation were added. Today there are numerous fiscal devices and sophisticated formulas to capture rent.
In the traditional concessionary system, the company pays a royalty, based on the value of the recovered mineral resources, and one or more taxes, based on taxable income. In its most basic form, a concessionary system has three components: royalty, deduction, and tax.
The royalty is normally a percentage of the gross revenues of the sale of hydrocarbons and can be paid in cash or in kind. Royalty represents a cost of doing business and is thus tax deductible. Other deductions typically include operating cost, depreciation of capitalized assets, and amortization. The revenue that remains after the fiscal cost has been deducted is called taxable income.
The definition of fiscal costs is described in the legislation of the country. Royalties and operating expenditures are normally expensed in the year they occur, and depreciation is calculated according to the tax legislation. The taxable income under a concessionary agreement is normally taxed at the countries basic corporate tax rate. Special royalty incentive programs and tax rates may also apply.
The exact manner in which costs are capitalized or expensed depends on the tax regime of the country and the manner in which rules for integrated and independent producers vary. Gallun8 discusses in detail the successful-efforts and full-cost methods used in US oil and gas accounting.
If costs are capitalized, they may be expensed as expiration takes place through abandonment, impairment, or depletion. If expensed, costs are treated as period expenses and charged against revenue in the current period. The primary difference between the two methods is the timing of the expense against revenue and the manner in which costs are accumulated and amortized.
Deepwater royalty relief in the Gulf of Mexico
In all royalty relief programs, the government provides an incentive for operators to invest in exploration and development activities to help subsidize "marginal" or "risky" development.
The relief programs are active for specific conditions under a predetermined time frame. A wide variety of targeted programs exists in the US, and in the offshore Gulf of Mexico (GOM), three programs are currently active: deepwater, deep gas, and marginal relief.
For leases acquired between Nov. 28, 1995, and Nov. 28, 2000, the OCS Deepwater Royalty Relief Act (DWRRA; 43 U.S.C. §1337) provided economic incentives for operators to develop fields in greater than 200 m (656 ft) of water.
The incentives provide for the automatic suspension of federal royalty payments on the initial 17.5 MMboe produced from a field in 200-400 m (656-1,312 ft) of water, 52.5 MMboe for a field in 400-800 m (1,312-2,624 ft) of water, and 87.5 MMboe for a field in greater than 800 m (2,624 ft) of water. The DWRRA expired on Nov. 28, 2000, but leases acquired during the time royalty relief was active retain the incentives until their expiration.
Reduction of royalty payments is also available through an application process for deepwater fields leased prior to the DWRRA but which had not yet gone on production. Provisions effective in 2001 are specified for each lease sale, are granted to individual leases (not fields as in the DWRRA), and are subject to change with each lease sale.9
If R denotes the royalty rate, Qt the annual hydrocarbon production from field f in year t, d(f) the (average) water depth of the field, and Q(f) the volume of production for which royalty is suspended, then deepwater royalty rates in the GOM are determined as shown in (1) in the box on this page.
Meta-modeling methodology
The impact of changes in system parameters is usually presented as a series of graphs or tables that depicts the measure under consideration (present value, rate of return, take, etc.) as a function of one or more variables under a "high" and "low" case scenario.
While useful, this approach is generally piecemeal and the results are anchored to the initial conditions employed. The amount of work involved to generate and present the analysis is also nontrivial, and the restrictions associated with geometric and tabular presentations of multidimensional data are significant; e.g., on a planar graph at most three or four variables can be examined simultaneously.
A more general and concise approach to fiscal system analysis, which has been developed by the authors and is believed to be new, is now presented.
The value of take (tc), present value (PV), and internal rate of return (IRR) varies with the selection of the oil price (Po), gas price (Pg), royalty rate (R), tax rate (T), contractor discount factor (Dg), and government discount factor (Dg)—among other factors—in a complicated manner through the cash flow model of the field. It is possible to understand the interactions of the variables and their relative influence using a constructive modeling approach. The methodology is presented in three steps shown in (2) on p. 44.
This procedure is referred to as a "meta-evaluation" since a model of the cash flow and fiscal regime is first constructed, and then meta-data are simulated from the model in accord with the design space specifications. The cash flow meta-data are used as input to develop linear models describing the influence and interaction of the system parameters.
The design base, cost structure, and production profile is assumed fixed, and so the relationships derived relate to the manner in which the system variables interact under a given development plan and fiscal regime. In a more general framework, these structures could also be considered design factors.
A good rule-of-thumb is to sample from the design space V until the regression coefficients "stabilize." If the regression coefficients do not stabilize, or if the model fits deteriorate with increased sampling, then the variables are probably spurious and linearity suspect.
After the regression model is constructed and the coefficients (k, a, b, g, d, e, u, l) determined, if the model fit is reasonable and the coefficients statistically relevant, the value of the system measures c(f) can be estimated for any value of (Po, Pg, R, Q, T, Dc, Dg) within Ω.
Na Kika development
The Na Kika deepwater development is 140 miles southeast of New Orleans in 1,800 m (5,800 ft) to 2,100 m (7,000 ft) of water (Fig. 1).
The project is a subsea development of five independent fields—Kepler, Ariel, Fourier, Herschel, and East Anstey—tied back to a centrally located, permanently moored floating development and production host facility on Mississippi Canyon Block 474.10 11 A sixth field, Coulomb, is in 2,300 m (7,600 ft) of water and will be tied back to the host facility as production capacity becomes available.
Shell and BP each hold a 50% interest in the host facility and in Kepler, Ariel, Fourier, and Herschel fields. In East Anstey, Shell has a 37.5% interest with BP holding the remaining 62.5%. Shell has 100% in Coulomb field.
The host is a semisubmersible-shaped hull with topside facilities for fluid processing and pipelines for oil and gas export to shore (Fig. 2). The fields will flow production from 12 satellite subsea wells equipped to handle 425 MMcfd of gas, 110,000 b/d of oil, and 7,000 b/d of water. Kepler, Ariel, and Herschel fields are primarily oil, while Fourier and East Anstey are mainly gas.
The API gravity of the fields ranges from 25º (Herschel) to 29º (Fourier). The first phase of production from 10 wells in Kepler, Ariel, Fourier, East Anstey, and Herschel is due onstream in the fourth quarter of 2003. Coulomb is slated to begin in 2004 from two subsea wells.
Next: Meta-modeling system as applied to the Na Kika group of fields.
The authors
Mark J. Kaiser (mkaiser@ lsu.edu) is an associate professor-research at the Center for Energy Studies at Louisiana State University in Baton Rouge. His primary research interests are related to policy issues, modeling, and econometric studies in the energy industry. Before joining LSU in 2001, he held appointments at Auburn University, the American University of Armenia, and Wichita State University. He holds a PhD in industrial engineering and operations research from Purdue University.
Allan G. Pulsipher is the executive director and Marathon Oil Company Professor at the Center for Energy Studies. Before joining LSU in 1980, he served as chief economist for the Congressional Monitored Retrievable Storage Review Commission, Chief Economist at the Tennessee Valley Authority, a program officer with the Ford Foundation's Division of Resources and the Environment, and on the faculties of Southern Illinois University and Texas A&M University. He holds a PhD in economics from Tulane University.
