Upstream Petroleum Economic Analysis: Balancing Geologic Prospectivity with Progressive, Stable Fiscal Terms and Instruments

Wumi Idelare, LSU, provides a primer on petroleum fiscal systems worldwide and discusses how the terms and requirements may potentially affect the attractiveness of a country's resources for development.

Offshore oil platform

Fiscal regimes describe all legislative, taxation policy, contractual, and fiscal elements under which petroleum operations are conducted in petroleum provinces or nations.

There are far more petroleum fiscal systems worldwide than petroleum-producing provinces. Kaiser and Pulsipher (2006) give some explanations for this phenomenon, including the fact that contracts originating under several different fiscal regimes may be in effect at any given point in time.

Other reasons cited include adoption of more than one fiscal arrangement during a licensing round, changes in political and economic conditions as well as in prospectivity assumptions of firms seeking the right to explore and develop petroleum resources, and the host government’s motivation to maximize economic rent collections from its country’s endowed resources.

Host Governments vs. Investors

Usually, the primary objective of the host government in a petroleum-producing nation is to ensure maximum economic benefits for the country without necessarily seeking total control of all exploration and production (E&P) terms and conditions, investments, and/or production. Other objectives may, however, be pursued, including efficient resource development, access to technology, skilled national manpower, investment funding for local E&P activity, and sustainable economic growth (Iledare, 2008).

On the other hand, investors tend to view host countries’ fiscal regimes critically on the basis of their financial objectives.

E&P firms or investors bidding for the right to explore and develop petroleum in a host country desire to receive a fair and satisfactory return on investment in a quick and orderly manner. Thus, some fiscal instruments and terms are negotiated while others are determined through the host country’s legislative process, keeping in perspective the host government and E&P firms’ objectives.

One important and critical concern to investors in deciding where to search for and develop oil and gas resources is stability in a host government’s fiscal arrangements (Johnston, 2003).

To attract investors to a petroleum region, an area must not only be highly prospective in the geologic sense, the area must also have a dynamic, efficient, and stable fiscal arrangement.

Dynamic and stable fiscal systems literally may require surrendering a great proportion of economic rents to investors to ensure the prospect of high rewards in countries with high exploration risk and low prospectivity.

Of course, if exploration risks are low and geologic prospects are high, then the host government can be expected to capture significantly high economic rents.

Investors have no obligation to develop petroleum resources in a given country when factors affecting the balance between the inherent risks and rewards are incoherent, no matter how promising the economic opportunities look..

Concessionary vs. Contractual Fiscal Systems

Certainly, the host government exhibits great influence and considerable leeway to avoid terms and conditions that could easily dampen investors’ interest in maintaining an operational presence in its country. Thus, over the years, operators and petroleum-producing countries’ host governments have negotiated their interests using two basic fiscal systems—concessionary or contractual.

The fundamental difference between the two fiscal arrangements has to do with ownership of petroleum resources and how taxes are imposed. In a concessionary system, the host government transfers ownership of resources to private entities, and in return gains a royalty or tax. Under a contractual system, the host government retains ownership of the petroleum resources.

A unique feature in all contractual arrangements is the cost-recovery limit (CRL) specification, which is based on allowable capital and operational expenditures with a “ring fencing” clause incorporated in most cases.

Classification of Fiscal Terms and Instruments

For the purposes of this discussion, the fiscal instruments and terms in a typical petroleum fiscal arrangement are classified as pre-discovery provisions, post-discovery contract terms, and profit-based elements.

Pre-Discovery Signature Bonuses and Rentals

Signature Bonus and Rentals—The application of pre-discovery payments in petroleum fiscal arrangements is common worldwide. Nearly half of all countries with petroleum fiscal systems include at least one form of pre-discovery payment to the host government.

The types of pre-discovery payment evident in fiscal regimes are signature, rentals, and discovery or prospectivity bonuses—they are not necessarily legislated but are negotiable. Such bonuses are classified as front-end loaded payments that are highly regressive.

Post-Discovery Royalties and Production Bonuses

Royalty—Royalties can be paid in kind or in cash and represent a cost of doing business. They are tax-deductible in oil and gas economic calculations.

The tendency in most fiscal arrangements is to define royalties using a sliding scale according to water depth, location, hydrocarbon type, and/or value.

If royalty rates are specified by value, they are designed to allow the host government to share in windfall profits subsequent to any unexpected increase in crude oil and natural-gas prices.

Production Bonus—Production bonuses provide future revenue to the host government when various levels of production and discovery are reached. Production bonuses permit the application of a sliding-scale payment schedule to rectify the repressiveness of production bonuses on the economic performance of E&P projects.

It is also apparent that there is a conscious recognition that production bonuses are payments that can create a barrier to entry, and reduce project cash flow as well as a venture’s attractiveness. Thus, the determination of production bonuses is allowed to be contract-specific.

Crypto Fees—Crypto fees are indirect means through which a government can receive additional revenue through levies, imposition of duties, and other financial obligations imposed on oil and gas producing companies. For example, the more prominent crypto fees or taxes in Nigeria include 3% of a project’s annual capital budget as a contribution to the Niger Delta Development Commission (NDDC) and an education tax of 2% of a project’s chargeable profit.

It is important to note that the instruments and terms highlighted above are not favorably disposed to assets’ profitability. They are front-end loaded and tend to lower profitability of assets in economic terms.

Post-Discovery Profit-Based Take

Corporate Income Tax (CIT)—Before the introduction of reform bills in Nigeria, for example, upstream companies were exempted from paying corporate income tax. Instead, a special petroleum profit tax (PPT),  based on assessable profits, was operational for every production-sharing contract (PSC) in Nigeria and the amount varied depending on location and hydrocarbon type.

It is interesting to note that a new taxation layer, called the Nigerian Hydrocarbon Tax (NHT), is being proposed. NHT, in my opinion, is analogous to severance taxes (taxes on production) paid to US petroleum-producing states by onshore petroleum-producing companies. This apparent double taxation is, however, not uncommon worldwide.

Education Tax—Several fiscal regimes in developing economies have an education or training tax in addition to a value-added tax (VAT). The former is based on quantifiable profit, which does not include capital allowances and the latter is based on sales.

Allowances—Interestingly, there can be a clear specification for an investment tax credit (ITC) and a petroleum investment allowance (ITA) as incentive mechanisms to drive E&P investment. It must be stated, however, that ITCs and ITAs are effort-based, so allowances on the basis of output (reserves addition or production) and/or prices are under consideration.

Profit Oil—Cost-recovery limit (CRL) specifications determine the profit oil (PO) to be shared between the host government and the contractor. Profit oil is defined as hydrocarbon revenues remaining after royalty and cost oil.

Commonly, there are provisions for a sliding-scale CRL based on volume, value, or some other variable to make the CRL dynamically progressive and less regressive.

The general consensus is to set the CRL at 70% to 80% of gross revenue less royalty. This is to ensure some minimum profit oil for distribution until all eligible costs are recovered.

The profit-sharing ratio is determined on a sliding scale in all Nigeria’s existing PSCs and the proposed reform bill. This is tied to either cumulative production or the R-factor (i.e., the ratio of cumulative cash receipts to cumulative expenditures in the conduct of petroleum operations as defined in the related contracts).

The Way Forward

Demand for environmentally friendly alternative energy sources is increasing, but fossil fuels are still the main energy source in the global economy. It does not appear that the status of fossil fuels will change any time in the near future. Increasing amounts of petroleum need to be found and developed to meet the growing energy needs of the developing world.

As alternative technologies are being developed, the search for new fossil-fuel sources will continue to stretch into more remote areas worldwide.

Certainly, technological advancements of the last several decades have improved efficiencies in exploration, drilling and completion, and production operations. These enhancements have given the industry the potential to search for and produce petroleum in a cost-effective and environmentally responsible manner.

As a result of improvements in seismic imaging, for example, areas once considered untouchable have become prime targets for petroleum exploration and development.

All of the above notwithstanding, the search for and development of petroleum resources having become more globalized, besides geological prospectivity, the attractiveness of fiscal regimes has become a lot more relevant to investment flow than in years past. This has increased the level of competition in the bidding process for oil and gas blocks and/or leases worldwide.

Thus, in order to attract investors, petroleum-producing regions must not only be highly prospective in a geologic sense, they must also have dynamic, efficient, and stable fiscal arrangements to facilitate optimal hydrocarbon resource development and reward.

A dynamic and stable fiscal system must include terms whereby host governments willingly give a significant proportion of economic rents to investors in order to promote the prospect of sustainable investment flow. High exploration risk and low-prospect regions must balance government take with attractive financial returns to investors.

Selected References

Iledare, O.O. 2008. Petroleum and the future of Nigeria: Challenges, constraints and strategies for growth and development. IPS Monograph Series No.5. Institute of Petroleum Studies, University of Port Harcourt, Nigeria. 30 pp.

Johnston, D. 2003. International exploration economics, risk, and contract analysis. Pennwell Books, Dallas, TX. 401 pp.

Kaiser, M.J. and A.G. Pulsipher. 2006. Capital investment decision-making and trends: Implications on petroleum resource development in the U.S. Gulf of Mexico. U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 2006-064. 130 pp.

Wumi Iledare is a professor of petroleum economics and policy research at Louisiana State University’s Center for Energy Studies and a distinguished fellow of the Nigerian Association for Energy Economics. Iledare, a recipient of an SPE Regional Award in management and information, is also a senior fellow and past president of the US Association for Energy Economics; 2013 president-elect and executive council member of the International Association for Energy Economics; and an associate editor of SPE’s Journal of Economics and Management. He serves as an adjunct or visiting professor of petroleum economics at five universities in the US and Nigeria, and has contributed to professional education and human capacity development by teaching petroleum economics at various professional organizations and businesses worldwide. Iledare earned a BSc degree in petroleum engineering with honors from the University of Ibadan, Nigeria; and also an MS in energy resources from the University of Pittsburgh’s School of Engineering and a PhD in mineral economics from West Virginia University—both with an emphasis on oil and gas economics.