Natural Resource Wealth Optimization: A Review of Fiscal Regimes and Equitable Agreements for Petroleum and Mineral Extraction Projects

Abstract

This review highlights the challenges of fiscal system optimization considering both the host government and extraction company perspectives. Countries around the world face an arduous task in determining the optimal fiscal system to maximize the capture of economic rents of natural resource extraction activities. The extraction industry is equally challenged to meet global commodity demand because the capital investments required for developing new hydrocarbon fields and ore mines are on the rise, while tax takes on extraction activities tend to rise too in many frontier jurisdictions. Normal profit must remain for the extraction companies, and returns must be large enough to replace for resource depletion. Companies use the benefits of resources produced in one country to finance capital investments for future field development in another country. One viewpoint is that profits are expatriated to the detriment of the host country and to the benefit of another country or the world supply chain as a whole. Another viewpoint is that all resource holders benefit because a foreign entity always starts in a new resource holding nation by investing in the development of an oil field or solid mineral mine using the profits from previous projects in other countries. A key question is What is a fair taxation regime for natural resource extraction in a particular geological setting and a given geographical location, taking into account subsurface uncertainty about the quality and volume of the resource, infrastructure needs and proximity to the world’s major markets and trade centers? Tax distortion could go both ways: either incentivize, attract and stimulate or des-incentivize, repel and deter resource development. Additional factors to consider are external uncertainties such as political and fiscal stability, sovereign risk and even local weather conditions (mostly in offshore and Arctic petroleum operations). Governments must tax the upstream rents of petroleum and mineral resources, but not to the level that suppresses extraction activities. All stakeholders want at least an equitable share of the profits. Defining what is equitable is a matter of intensive negotiations, renegotiation of prior agreements and sometimes litigation and international arbitration. Several case studies, covering both petroleum and solid mineral extraction projects, are included to highlight the key points involved in fiscal policies designed to optimize the utility of geological resource endowments. For example, the offshore tax regime employed in the US pivots the trade-offs between fiscal incentives and long-term resource supply to ensure energy security. This review concludes with a call for further research.

Appendices

Appendix 1: Brief Outline of Mineral Royalty and Taxation Rate Mechanisms

The range of mineral royalties and taxation rate mechanisms in the mining sector is briefly outlined below. The review shows that in rem taxation systems tend to provide steady revenues for the treasury as long as a mine delivers plateau production volumes, but no share in any windfall profits due to rising commodity prices. In personam taxation systems are better suited when the treasury would want a share in windfall profits. The trade-offs between short-term cyclical gains and long-term success must be carefully considered in mining agreements. Mining projects remain sensitive to cyclical commodity prices which may affect mine longevity as dictated by cut-off grade analysis.

Mining Royalty Systems

The below review of mineral royalties and taxation rate mechanisms in the mining sector draws extensively from previous studies (Otto et al. 2006; Harman and Guj 2006; ICMM 2009; Land 2010; PWC 2007, 2012; IMF 2012; Smith 2012a, b; Guj et al. 2013).

Otto et al. (2006) concluded that the geological, economic, social and political circumstances of each nation are unique, due to which royalty taxing is no one size fits all mechanism, but must be tailor-made to be optimal for each specific case. A recent summary of mining taxation by PWC (2012) stated that “major challenges often lie in the administration of the rules and regulations by the tax authorities, rather than in the legislation itself.” Various aspects of tax administration efficiency have been discussed in several recent studies (Collier et al. 2009; Calder 2010a, b; Guj et al. 2013).

Nations with weaker tax compliance and poorly developed tax administration tend to apply taxes based on revenue value-based (ad valorem) or production unit-based royalties (both are so-called In rem tax systems). Table 7 provides generic examples of the various types of In rem and In personam taxes. In addition, there may be in kind benefits such as infrastructure investments and social projects. Unit-based royalties may discriminate between scales of operators, with larger operations subjected to steeper royalties, while family or cooperative run operations pay lower rates. Some of the taxes indicated in Table 7 are less current as discussed in detail in Otto et al. (2006).

Table 7 Main categories of royalty taxes levied on mining operations (source: Otto et al. 2006)

Effects of Mineral Taxation Policies

The amount of mining revenues that could be taxed away (Fig. 29) generally aims to capture part of the economic rent. Nations with well-developed tax administrations tend to use profit-based and capital gains-based mining tax systems (in personam taxes). Profit-based taxes do not lower the economically recoverable quantity of resources (q* in Fig. 29). For example, most Canadian Provinces use profit-based mining taxation, as well as Nevada in the U.S. and the Northern Territory in Australia. Based on corporate income tax, the share of profits taxed is 35% in U.S. and Chile, 30% in Australia, Indonesia, Papua New Guinea and Zambia, 28% in Mexico and South Africa, and 22% in Canada (2008 rates; in Hogan and Goldsworthy 2010). In personam taxes require a general level of tax compliance and a tax authority with administrative capability that will perform audits when needed. The tax system must be judicially well-developed and well-understood to enable compliance by operators.

Fig. 29

Ultimate recoverable reserves for risk neutral development scenario is q _RN. Risk premium reduces the cut-off grade to q*. The commodity reference price on the world market is assumed at P _W. The risk-adjusted commodity production supply curve is given by S _RA, and risk neutral supply curve would be S _RN. (Graph source: Hogan and Goldsworthy 2010)

Figure 30 shows the effect of revenue-based royalty, which lowers the total recovered resource quantity (q _adv in Fig. 30), because the economic cut-off grade needs to be higher, to pay for marginal extraction nearer the end of the mine’s life. The so-called high grading is stimulated by revenue-based taxes (an in rem tax mechanism). Revenue-based royalties (Ad valorem royalties of in rem tax type) are applied in Western Australia (7.5% of the realized sales value of crushed ore, 5% for concentrate and 2.5% for metals). Botswana used at some stage uniform royalty rates at 10% for revenues from precious stones, 5% of precious metals an 3% on other minerals. The “royalty value” is commonly defined as “sale value receivable at the mine gate in an arm’s length transaction without discounts, commission or deduction for the mineral or mineral product on disposal.” The royalty value is a market value that may be tied to a reference price from a mineral exchange.

Fig. 30

Ultimate recovered resource volume under ad valorem revenue-based royalty schedule is given by q _ADV. Royalty revenue slice is the taxed fraction of revenues P _W q _ADV, which lowers the local net revenue price for the producer relative to the world market by (1 − t _ADV)P _W. (Graph source: Hogan and Goldsworthy 2010)

When revenue-based royalties are levied irrespective of profitability, a proportion of the previously economic grade will be lost to impairment. Such royalties continue to flow even when a drop in the commodity price temporarily renders a mine unprofitable. If this scenario develops, lowering the royalty may keep a mine profitable thus longer active for a certain cut-off grade. A lowered royalty may lengthen the life cycle of a mine, assuming optimal cut-off grade can be maintained. This will also keep royalties flowing longer and therefore may result in a larger cumulative government take.

Revenue-based and unit-based royalties can destruct value for both the operator and the resource holder, unless rebate clauses are built into the mineral taxation system. Commodity prices nearly always drop during an economic recession because a global GDP contraction generally results in cutbacks of construction and production activities. Reversely, GDP growth of about 3% is commonly accompanied by construction booms with increased industrial output by as much as 10%, leading to rapid price hikes in building aggregates and other mineral commodities. Mining profits grow when global GDP spurts, but shrink when recessions hit the market. Cut-off grade analysis is required to adjust the mining plan accordingly.

For industrial minerals, unit-based royalties are the prevalent system used. An example of unit-based royalty system is Net Smelter Return (NSR), which sets a charge per unit of ore returned from the smelter. The taxable value of NSR is based on the value of smelter concentrate volume produced, adjusted for certain allowable costs incurred. Figure 31 shows the effect of a combination of ad valorem royalty and income-based taxation. In the mixed taxation schedule, the ad valorem part lowers the total recovered resource quantity (q _mix in Fig. 3a, which equals q _adv in Fig. 30), because the economic cut-off grade again needs to be higher, to pay for marginal extraction when the end of the mine life nears. The ideal solution of a non-distorting tax is certainly not achieved by unit-based royalty and to a lesser extent by ad valorem ones. However, there are important practical arguments for unit-based taxation in some jurisdictions with weak institutions.

Fig. 31

Combined effect of ad valorem and profit-based resource rent taxation. (Graph source: Hogan and Goldsworthy 2010)

Adopting an Appropriate Taxation Regime

Countries must carefully weigh their options and set mineral extraction taxation at appropriate levels to ensure (1) attractiveness for investors and (2) retention of an equitable share in return on natural resource depleted by the extraction process. The choice between in rem and in personam tax systems is an important one. Nations like U.S. and Sweden do not charge any federal royalties on mining, and exclusively rely on federal income taxes for offshore concessions supplemented by auction premia and production share royalties. In some U.S. states, additional profit-based taxes are imposed (e.g., Nevada). Some countries with relatively weak tax administrations and poor compliance with taxation rules (like Chile, Peru, Mexico) have also forsaken mining royalties. In the case of Chile, mining royalties were finally introduced in 2006, which have since corrected the country’s historic lack of mineral wealth sharing. The earlier rescinding of Chile’s copper wealth remains an important example of past government policies that forfeited a significant part of the nation’s mineral wealth legacy (see case study in “Case Study: Chilean Copper Mine Taxes” section in Appendix 1). The country is now catching up with mineral wealth value accrual in its copper SWFs (Table 4, main text).

In Angola and China, royalties are negotiated by government representatives on a mine-by-mine basis so that rates are balanced to fit the unique features of the mineral prospect targeted for development. This discriminatory taxation is also well-known from petroleum projects in many developing nations. Bigger resources are subject to tailor-made “discriminatory” taxation regimes and/or profit-sharing schedules. Most governments that use profit-based tax apply a rate in excess of 5%, while ad valorem royalty on copper commonly apply rates between 1 and 4%. The reason is that unit-based payments are steady, while profit-based remittances may see years with no tax payments due to lack of profits. Although the administrative burden for governments seems lower for unit and ad valorem royalties than for profit-based systems, the in rem taxes need to be periodically reviewed, indexed and adjusted in order not to move out of line with inflation rate and global commodity price cycles. Royalty revisions may be prudent when rates have become disproportionate (too low or too high), or when a new commodity is to be mined.

A comparative analysis by John Stermole of unit-based, ad valorem-based and profit-based royalty systems is given in Table 8. This sets the rate required for a government to receive annually the same fixed amount of tax income ($20 million in this case). It follows that the percentages range between 1.17 and 4.91%; the unit-based rate is a fixed value per weight unit produced.

Table 8 Royalty rates required to earn the same FEP for a hypothetical Nickel mine as detailed by John Stermole in Otto et al. 2006)

One could say that profit-based taxation without royalties is adequate for nations where major mining companies are incorporated in the same country, in which case most profits are ultimately reinvested in the country (and not expatriated). This situation also requires a well-developed tax administration. In developing nations, mining profits are commonly expatriated by foreign operators. In such cases, unit-based and/or ad valorem royalties provide a sure base income for the State, but also lead to high grading, leaving low-grade resources unrecovered. An important reason for forsaking profit-based taxation is that profits are commonly accounted at corporate level which are difficult to relate uniquely to a specific mine project due to the practice of consolidated reporting. Profit-based royalties may remain absent until a mine has recouped all its investment. Instead, unit-based and ad valorem taxes are levied at project level and imposed at the mine gate. Unit-based and ad valorem payments help bridge the income gap for the host government and help to appease any public perception that the mine delays profit-sharing unfairly—because unit-based payments start flowing to the treasury as soon as production commences.

A profit-based tax rate that ensures a share in windfall profits seems reasonable. For example, one could consider geared royalties (Collier 2010) or progressive royalty rate on profits, which for Angolan oil contracts is IRR-based an moves from a base rate of 25% profit share for IRR ≤ 15%, to 35% for 15 < IRR ≤ 25%, to 55% for 25 < IRR ≤ 30%, to 75% for 30 < IRR ≤ 40% and to 85% for IRR > 40% (Nakhle 2008, 2010). A drawback of profit-based taxation is the considerable risk of disputes and litigation about deductibles. In practice, companies may have excessive room for deductions which minimize booking of profits in subsidiaries by transfer pricing: importing mining machinery at inflated cost prices and selling mineral exports below market value. These situations may lead to incurrence of costly legal fees that drain the treasury. Such disputes can only be avoided or at least minimized if the tax authority is empowered and issues a set of consistent and fully understood legislation on applicable royalty rates. Governments seek to maximize revenue from taxes and royalties and minimize cost of legal fees and political risk. Continual consultation and dialog and information provision to tax authorities should be honored and accommodated by mining companies. If a mining company fails to comply, appropriate penalties should be imposed and promptly collected upon risk of forfeiture of assets.

Fiscal Stability Agreements

When a mining company makes an investment in a country, it is possible in some jurisdictions to agree to a level of fiscal stability with the government, such that certain tax increases will not apply to the company under the terms of the stability agreement (Daniel and Sunley 2010). For example, Argentina has a statutory fiscal stability agreement with a term of 30 years. Chile also has a fiscal stability regime, which sets down certain rights and benefits for non-Chilean investors, including taxes such as the specific mining tax rate and mining licenses. The Republic of the Congo permits a mining company to enter into a tax stability agreement in which the tax rates and tax base are negotiated with the government and the specific tax regime must be ratified by the government to be enforceable. Indonesia has historically entered into tax stability agreements, but Indonesia’s system of tax stability contracts between the government and the mining company ended in 2009. The Indonesian government is seeking to re-negotiate its existing mining “Contracts of Work” to bring mining companies in line with the current tax regime. Despite the existence of fiscal stability agreements, in Peru likewise, the government enacted a special mining contribution applicable to companies with tax stability agreements. The Peruvian government requested that companies voluntarily enter into agreements with the government to pay the special mining contribution. Accordingly, the existence of a tax stability agreement does not necessarily ensure that the government will not try to re-negotiate the tax stability agreement should the country have a substantial drop in tax revenues or increase in government expenditures during a crisis situation or economic downturn.

Meanwhile, many governments have adopted “ring fencing rules,” which provision that companies in determining income subject to corporate income tax will no longer be allowed to offset the losses incurred with respect to one mining site against the profits generated from another mining site. For example, Kazakhstan requires companies operating several assets to maintain separate accounts and records for tax purposes with respect to each activity (PWC 2012). The subsurface contract miner is not permitted to offset costs of one mining contract against income of another contract or activity. Since July 2010, Tanzania also has a “ring fencing rule” in that losses incurred in one mine cannot be used to offset profits of another mine, notwithstanding that both mines are part of the same legal entity. Ring-fencing rules apply as well in Ghana.

In general, many historic mining contracts have low royalty rates, and countries are seeking to raise tax revenue. However, unit-based and ad valorem royalties generally feature provisions for payment relief in case of cash flow hardship due to commodity price weakness. If employment creation is important and mineral grades are too low to generate reasonable profits, then governments should consider waiving even unit-based taxation in favor of marginal monetization of the natural resource.

Fiscal Regime and Company Profits

Figure 32a, b shows an example of the cumulative cash flow model for a hypothetical copper mine for a certain royalty level that remains static over the 22-year life cycle of the mine assuming a stable global economy. The assumed 18% discount rate flattens cumulative cash flow, which in year 7–8 of the mine life leaves no NPV growth. Prudent investors would close the mine when after tax cash flow turns negative, which occurs in year 8. The sensitivity analysis to tax rates suggests that the government benefits most from the highest royalty rates (Fig. 33a, b). However, for the mining company, the projects NPV and IRR erode rapidly with increasing government take, to a point where it would become unattractive for a company to remain engaged. The mine could close prematurely. If that were to happen, resource wealth becomes de facto sub-economic (i.e., the reserves are impaired). Such impaired resources, of course, may turn economic again when another mining company engages and takes a final investment decision to develop the resources, but this remains uncertain until it actually happens.

Fig. 32

a, b Cumulative cash flow (solid curves) for a hypothetical copper mine project discounted at 18%. The NSR royalty rate paid to the government is 0% in (a) and 3% in (b). In both cases, the NPV does not grow after year 8, due to the discount rate applied and equipment replacement cost incurred in year 11. (Graph source: John Stermole in Otto et al. 2006)

Fig. 33

a Project NPV (for company) and cumulative FEP (for government) as a function of NSR royalty rate. b Project IRR (for company) and FEP take (government) sensitivity to NSR royalty rate. The IRR remains around 18% according to the original data plotted here, but may be due to a special less current definition of IRR. Traditionally, project IRR is likely to deteriorate in line with NPV erosion. Henceforth, when NPV erodes fast as in plot (a), the IRR is likely to drop rapidly unlike that shown in plot (b). The data for NSR = 6% seem off, and are corrected by the dashed line. (Graphs plotted from source data in John and Frank Stermole in Otto et al. 2006)

Case Study: Chilean Copper Mine Taxes

Revenues from copper mining projects for a long time have been very mildly taxed in Chile, although the country has been responsible for nearly 40% of global copper supply (Otto et al. 2006). Royalties were only introduced in 2006. Over the period 1990–2001, the Chilean treasury had received a little over $10 billion from its state mining company Codelco, but only $1.6 billion from private companies over the same period (Pizarro 2004). The taxes received compared to overall production means Codelco paid en effective FEP rate of 28.7% and private operators only 5.3% (Pizarro 2004). Most of the FEP is based on corporate income tax, and private mines have been actively evading tax payments by transfer pricing, fiscal evasion practices and creative accounting solutions.

The development of Disputada de las Condes mine provides a striking case study for the apparent divergence in interests between the state and the operator. The Chilean copper industry resurged in the early part of the 20th Century. Anaconda and Kennecott, two U.S. registered companies owned the four major mines since WWII. The properties were nationalized in 1971, by consolidation into Codelco. A real copper bonanza re-occurred in the 1990s with many foreign operators opening mines in Chile (Table 9). La Disputada, now operated by Anglo American, was one of the first to be picked up by foreign investors after Chile’s socialist government of Allende was overthrown in 1973 by Pinochet, who liberalized the market economy (but nothing else)—once again.

Table 9 Mining companies active in copper mining in Chile over the years

Exxon bought Disputada in 1978 and operated the mine for 22 years before selling to Anglo American in 2002 (Aguilera 2004). Exxon never paid any taxes on its copper production by utilizing accounting space to forward carry losses and by applying interests on expensive loans from its parent company via an unusually high debt-to-equity ratio of its Chilean subsidiary. Even at the time of the mine’s sales, Exxon claimed no capital gains tax would be due; Chilean taxation rules would not be applicable to its mine sale. Exxon’s book value for La Disputada was only $500 million, but the mine was sold for $1.3 billion to Anglo American, which implied $800 million capital gains was realized by Exxon, that is before tax. Chilean law stipulated 35% tax on capital gains was due from mining asset sales. The $280 million tax due to Chile was never paid by Exxon. After a long litigation, only $27 million was doled out by the company as a capital gains tax compensation, but the company vehemently maintained its prior agreement with the government would dispense it from any capital gains taxation plight.

Finally, a sliding-scale revenue-based royalty (0–5%) was introduced by the Chilean government in 2006 (Hogan and Goldsworthy 2010), which has already lead to the accumulation of over $22 billion in its copper funded SWFs as per January 2014 (Table 4 in main text).

Appendix 2: Brief Outline of Principal Agreements for Oil and Gas Resource Development

This summary is based on data compiled by Oswald Clint, Iain Pyle and Rob West at Bernstein Research (Clint et al. 2013).

Royalty and Taxation Agreement (RTA)

The majority of OECD countries tax oil and gas production using a royalty and tax regime. Royalties are charged as a percentage of revenue earned from production, and income taxes are then charged as a percentage of operating profit. Table 10 includes a simplified example of the government entitlement under RTA. Under a royalty and tax regime, the tax rate is not sensitive to the oil price, making the net income of operating companies more sensitive to the oil price than under other tax regimes. This can be a relatively simple tax system: The income tax rate charged will often be the country’s standard corporate tax rate plus an additional resource tax, as is the case in Norway. Brazil is another example of a royalty and tax regime, but one that is more complex. Royalties are charged at 10%, and Brazilian corporate tax is charged at 34%. However, there is also an additional Special Participation Tax (SPT) charged on the pre-salt fields of 40% prior to corporate tax, making the income tax charged on oil and gas production actually 61.4%. The SPT and royalties are reported under production cost, and just the corporate tax is shown as income tax. Reporting of production taxes is inconsistent even with the FAS 69 disclosure (FASB 2010).

Table 10 Simplified project economics and government FEP for the taxation regimes under the three different main types of contract

Production Sharing Agreement (PSA)

PSAs are generally used by non-OECD oil and gas-producing nations. A simplified PSA is described in Figure 34. When oil or gas is produced, the operating company can recover costs of production (this portion of production is termed Cost Oil), before any additional volumes (Profit Oil) is split between the government and the contractor. The ratio of the Profit Oil split is determined by a sliding scale, which is based on complicated formulas generally established by the IRR for the project to date. Table 10 (middle column) includes an example of government entitlements under PSA. The tax take also varies significantly through the life of the project. In the early stages, while the operator is still recovering CAPEX, the IRR up to that point is low and therefore the government’s share of Profit Oil is low; in later years, CAPEX spend slows and the IRR likely moves above a threshold, meaning the government share of Profit Oil increases, often to a proportion of around 80%. PSA tax regimes tend to be sensitive to the oil price. A high oil price means that operators earn costs back quickly and have higher returns, resulting in the government taking an increased share of production.

Fig. 34

Simplified project economics comparing operator profits and FEP payments to government according to a generic PSA schedule. Source: Bernstein Research

Service Contract Agreement (SCA)

The third type of tax regime is a service contract agreement, which is much less common than tax rates or PSAs. The integrateds have some exposure due to SCAs being used in the UAE and Iraq for contracts awarded after the second Gulf War. Under the service agreements, the operators receive a fixed fee for each barrel of oil produced above a fixed level. The fees in Iraq range from as little as $1.15/bbl (for West Qurna-2, operated by Lukoil) to $6/bbl (for Najmah, operated by Sonangol). Under the agreements, the income of the operators remains insensitive to any oil price windfall or loss. Table 10 includes an example of the government FEP under SCAs.

Case Study: U.S. Federal Oil and Gas Royalty and Taxation

The below treatise on the evolution of U.S. federal leasing policies is largely based on sources and details summarized in a popular essay by Freudenberg and Gramling (2011) and Krueger and Singer (1979). Leasing of land from private mineral right owners in the U.S. is concisely covered by Tinkler (1992) and McFarland (2006). Terms used for U.S. oil and gas taxation are defined a by the U.S. Internal Revenue Service (IRS 2013).

Initially, the U.S. federal Mining Law of 1872 commonly would grant a claim patent in exchange for about $5/acre. In 1913, U.S. Congress granted mining and oil companies a depletion allowance, amounting to a tax deduction of 5% of the gross value of production to enable investment in the development of new mines, essentially granting a Hotelling rent. The War Revenues Act of 1918 revised the 5% tax break based on gross production with a provision to deduct either the cost or the fair market value of a new discovery, which could amount to 28–31% of the companies’ gross income. In 1926, the War Revenues Act was changed to 27.5% of gross income, which basically lasted until the 1970s, when U.S. tax policy effectively allowed oil companies to defer taxes on roughly a quarter of the production income.

Leasing of federally owned land was first made possible by the Mineral Policy Act of 1920, which replaced the previous Mining Law of 1872. The Mineral Policy Act granted 10-year leases for the right to extract publicly owned deposits of oil and minerals. The general principle was that the leases would be awarded based on a competitive bidding process. However, there were irregularities of which Teapot Dome Scandal was one of the most notorious. It involved Secretary of the Interior, Albert Fall, who was convicted and jailed for accepting bribes for the awarding of Naval Petroleum Reserves without competitive bids between 1922 and 1923, including Teapot Dome, Wyoming (Davis 2001; McCartney 2008).

California was the first state to adopt a legal framework for the leasing of offshore tracts, i.e., in the Santa Barbara Channel, in the early 1900s. In 1929, the California State Mineral Leasing Act was repealed and offshore leasing curtailed. That year President Hoover also withdrew federal lands from leasing in an attempt to counter the risk of overproduction of oil after major discoveries in Texas, Oklahoma and California. In 1931, state laws were passed in both Texas and Oklahoma to prevent exceeding production quotas, but prices continued to fall, which lead to the imposition of import tariffs on foreign oil. In 1927, the first oil cartel meeting took place in Scotland where Shell, BP (then Anglo-Persian) and Exxon (then Standard Oil) worked out the Pact of Achnacarry (Yergin 1991). Price fixing by the international petroleum cartel was uncovered by the U.S. Federal Trade Commission in a 1952 report (FTC 1952), but was continuing at least until the oil embargo of 1973–1974.

Although states that experimented with offshore leases (Louisiana, Texas, Florida and California) had been assuming that they were the legal owners of offshore tracts, the federal Government did not agree. Assertion of Federal ownership was first attempted in a resolution proposal to the U.S. Senate in 1937 (Harold Ickes), but the House of Representatives took no action. The State Land Act of 1938 gave California legal control over offshore leasing and limited offshore development resumed. Louisiana offered its first ever offshore lease not until 1945, granting a 194,000 acre tract to a single bidder company (Magnolia Petroleum Co.) that later became part of Exxon Mobil. Lousiana Caddo Lake field (Louisiana) was developed in the 1910s using shallow platforms, which were subsequently moved to the 12-feet deep Lake Maricaibo (Venezuela) with a first well drilled in 1924. Pipeline corridors in the Louisiana marshes were already common where large-mounted draglines carved a network of canals in the wetlands and cleared the way for the Giliasso drilling barge around 1932.

In 1945, Harold Ickes persuaded President Truman to issue Executive Order 9633 (FR12304(1945);59 Stat. 885) and asserted federal ownership of offshore oil lands. A federal suit was initiated against California in the U.S. Supreme Court in what became known as “The Tidelands Controversy” (Engler 1961; Cicin-Sain and Knecht 1987). Texas and Louisiana continued with leasing and legal battles with the federal government dragged on for years until the U.S. Supreme Court established the legal rights of the federal government over all offshore lands in a series of decisions between 1947 and 1950.

In 1953, U.S. Congress passed the Submerged Lands Act, granting states title to seaboard within 3 miles of the shoreline, but asserting federal ownership of all resources under federal offshore waters. Texas and West Florida received a state seaboard of 3 marine league (approximately 10.4 miles) in their ruling. The second law adopted was the Outer Continental Shelf Act (OCSA) which offered leases through a competitive bidding process. California and Florida and Alaska had successfully opposed federal lease auctions in Washington DC District Court since the mid 1970s.

In 1978, the Outer Continental Shelf Land Act Amendment (OCSLAA) stated purpose was to open the decision-making process to a wider audience and avoid collusion between a small group of bidders and top-officials of the Department of the Interior.

In 1983, the area-wide sales were introduced by James Watt of the U.S. Mineral Management Service (MMS). Offshore leases typically cover a 3 mile square block which contains 5,670 acres. Traditionally, offshore leases required that federal government receives the bonus bids, plus one sixth of the total value of offshore resources extracted (16.666%). When area-wide sales started in 1983, some leases in greater water depths were offered with a royalty discount, demanding only one-eighth of the gross resource value produced (12.5%) to stimulate deep-water E&P. Before 1983, the average acre dollar was $2,224. The area-wide leases sold between 1983 and 2008 averaged just $263/acre.

In 1995, U.S. congress passed the Outer Continental Shelf Deepwater Royalty Relief Act (DWRRA, 1995). This is a royalty waiver program aimed at stimulating development of hydrocarbons in the deep-water Gulf of Mexico. Royalties were suspended for 5 years in a tiered system that allowed royalty-free production in deep-water areas of the GOM, defined as water depths below 200 meters, as follows:

• 200–400 m: 98.5 bcf gas and 17.5 MMbbls oil royalty free

• 400–800 m: 295.6 bcf gas and 52.5 MMbbls oil royalty free

• >800 m: 492.6 bcf gas and 87.5 MMbbls oil royalty free.

The original terms and conditions of the DWRRA expired in November 2000, and since that time, the MMS assigns a lease-specific volume of royalty suspension based on how the determined suspension amount supports field development economics. According to the U.S. Government Accountability Office, the waiver reduced the tax burden of the companies by $50 billion over the life of the leases (GAO 2007). The fiscal take in the Gulf of Mexico was estimated to amount to 45% based on Clint et al. (2013) and Hendricks et al. (1987) estimated a fiscal take of 77% leaving only 23% for company profit, but incorrectly assumed a lease bonus as a cost rather than a tax deductable. Offshore lease actions in the U.S. between 1954 and 1990 have raised $282 billion, and the royalty to the government at 1/6 (16.666%) of revenue amounted to $202 billion (Porter 1995; Cramton 2010).

The effect of fiscal stimuli on the development of new productivity becomes apparent in a compilation of the annual oil and gas production in the U.S. Gulf of Mexico plotted against tax measures taken (Fig. 35). Particularly, field development in ultra-deep water was stimulated by the 1995 royalty waiver program. The lifting of the drilling ban for outer portions of the continental shelf by president Bush Jr. before he left office in 2008 lead to another brief revival of drilling activity.

Fig. 35

Annual production output from the U.S. Gulf of Mexico. Adapted from Bernstein Research

Case Study: Kazakhstan Production Sharing Agreements

The Caspian Sea region is an emerging oil and gas play, where the interests of oil and gas majors and sovereign resource holders meet and struggle for mutual profit optimization. Some U.S. energy firms and other private foreign investors have become discouraged in recent years by harsher Kazakh government terms (Nichol 2013). Foreign investors report that local government officials regularly pressure them to provide social investments in order to achieve local political objectives. In 2009, the Karachaganak Petroleum Operating (KPO) consortium (the main shareholder is British Gas, and Chevron is among other shareholders), which extracts oil and gas from the Karachaganak fields in northwest Kazakhstan, was faced with an effort by the Kazakh government to obtain 10% of the shares of the consortium. Facing resistance, the government imposed hundreds of millions of dollars in tax, environmental, and labor fines and oil export duties against KPO. Both the government and KPO appealed to international arbitration (Nichol 2013). In December 2011, KPO agreed to transfer 10% of its shares to the Kazakh government, basically gratis, and in exchange the government mostly lifted the fines and duties. In July 2013, Kazakhstan exercised its right to influence the disposition of subsoil resources by directing the transfer of the United States’ ConocoPhillips 8.4% stake in the Kashagan oilfield to the China National Petroleum Corporation (Nichol 2013). ConocoPhillips had planned to sell the stake to India’s Oil and Natural Gas Corporation. Other members of the North Caspian Operating Consortium developing the oil field currently include Italy’s Eni energy firm, the Anglo-Dutch Shell, the United States’ ExxonMobil, France’s Total and Kazakhstan’s KazMunaiGaz (all with a 16.81% stake) as well as Japan’s Inpex (7.56%). Rising concerns over the Kazakh government’s policies raised questions among the investor community backing the foreign consortium members about the timeline and feasibility of their efforts as a source of rising revenues from the oil field.

Appendix 3: Governance Issues Related to Transparency and Accountability of Corporate Profits and Fiscal Entitlement Payments in Natural Resource Extraction Activities

Transparency About Concession Agreements

Oil companies generated from natural resource exploitation corporate profits based on projects with profitable IRR. A fiscal entitlement payment (FEP) is due to governments with the intention to benefit the national treasury. Corporate profits and FEPs of major oil and gas projects can amount to billions of dollars per year. Governments received FEPs as specified in concession and licensing agreements (see Appendix 2). Precisely how much money is paid in individual projects and to whom remains often hidden in consolidated profit-loss accounts of companies and the same rules for the mineral resource treasuries of many nations (both OECD and non-OECD).

One could argue that information pertinent to a nation’s natural resource wealth sharing should be publicly available because it is in the interest of the people whose legal representatives must responsibly manage the resources of a given country. Independent research is handicapped by the fact that many concession and licensing agreements are confidential. Nearly all companies consider their contracts as proprietary information with competitive value. The majority of governments closely guard their agreements for individual fields in the same way, so that details often remain shrouded in obscurity. In fair trade, it remains important to know precisely how natural resource endowments are exchanged into long-term wealth for a country and its citizens.

Accountability Standards and Rating of Oil Funds

The Resource Governance Index (RGI) outlined in the main text subsection “Reputation of the Mining Industry” is not only applied to countries but also to a pool of natural resource funds (SWFs) and to a number of national oil companies (100% state-owned or partially state-owned after partial privatization). Table 11 lists the RGI scores for SWFs related to petroleum revenues. Comparison to Table 3 in the main text reveals that some of the largest SWFs have RGI scores less than 70 and therefore are governed in a manner that is only partially fulfilling RGI standards (RGI 70-51), outright weak (RGI 50-41) or failing (RGI below 40). The RGI assessment by the Revenue Watch Institute can be compared with the Linaburg–Maduell Transparency Index (LMTI), developed by Carl Linaburg and Michael Maduell at the Sovereign Wealth Fund Institute. The LMTI is another method of rating transparency pertaining to government-owned investment vehicles. The index is based on 10 essential principles that depict SWF transparency to the public. The minimum rating a fund can receive is a 1 and maximum a 10. Low scores apply when there have been concerns of unethical agendas and “opaque” or non-transparent governance of funds. Transparency ratings may change as funds release additional information.

Table 11 RGI and LMTI of World Major Petroleum Funds (SWF Institute 2014; Revenue Watch Institute, RWI 2013)

Scores of LMTI are included in Table 11. This also reveals consistencies in SWF governance ratings (Norway, Russia, Iran, East Timor), but also some great disparities (Kuwait, Qatar, Azerbaijan, Mexico), with reasonable close ratings for a number of countries (Kazakhstan, Canada, Algeria, Nigeria, Trinidad & Tobago). Clearly, the rating of SWF governance is in its infancy.

Rating of National Oil Companies

National oil companies are a main source of GDP and fund a major portion of government budgets in many nations. For example, more than two-thirds of total government revenue in Azerbaijan, Iraq and Yemen are funded by the profits of their respective national oil companies (RWI 2013). Table 12 lists the RGI scores for the governance performance of major national oil companies (some of which have been partly privatized, e.g., Statoil and Petrobras). The accountability of national oil companies that Revenue Watch Institute measures is the company’s compliance with international accounting standards, disclosure of data and audits on production and revenues, publishing of reports that are transparent about risks of extra-budgetary spending and disclosure of company contribution to the government budget. It is worth noting that the world’s largest oil producer, Saudi Aramco with an outstanding technical record, scores a meager RGI of 42 (Table 12).

Table 12 RGI Scores National Oil Companies—Revenue Watch Institute—(RWI 2013)

National oil companies that are 100% state-owned and derive a major part of their revenues from domestic upstream activities do not experience the polarized viewpoints that govern negotiations between foreign companies and governments that manage national resource endowments they want to develop and produce. However, state oil companies are essentially regulated companies, which must fiercely negotiate with their regulatory agency to make sure that enough earnings are retained for new capital intensive development projects. For such negotiations, it is useful to avail better tools for establishing the fair value in extraction projects. This will help finding a right balance between government FEPs and profits retained for sustained operations by the national oil company.

Transparency of International Oil Companies

International oil companies have annual revenue streams surpassing the GDP of many countries in which they hold assets. For example, Shell 2012 revenues of $467 billion exceed the combined 2012 GDP of Nigeria, Angola and Gabon (Fig. 36a). A recent report by Africa Progress Panel (Geneva; APR 2013) has highlighted how collusion of the extractive industry and weak governments can deprive nations from receiving fair value for its extracted natural resources. Shell was not implied in this study, but the mining industry was shown to be complicit. A detailed analysis of five major mineral extraction concessions in Congo granted in the period (2010–2012) lead to the conclusion that these were underpriced (APR 2013), and resulted in a compounded loss for the Treasury of $1.36 billion. The lost sum would have been sufficient to cover twice the total health and education budget of Congo (Fig. 36b). Clearly, governance of natural resource wealth is still weak in many nations, and there is ample room for improvement (RWI 2013).

Fig. 36

a Shell’s 2012 annual turnover is larger than the 2012 GDP of Nigeria, Angola and Gabon combined. b Concession losses on five deals in Congo during (2010–2012) would be enough to cover twice the country’s health and education bills. Source: APR (2013)

Petroleum laws being developed or reformed, particularly in many African countries, will have an important bearing on citizens and civil society groups to secure access to natural wealth-sharing information. A recent survey of petroleum laws of five countries (Ethiopia, Ghana, Liberia, Uganda and Zimbabwe; Veit and Excell 2013) reveals weak provisions for the enforcement of the right to access information, and appeal against refusal. Some laws oblige the executive branch of government to report to the legislature, but the detail of the information to be provided remains a matter of interpretation (Veit and Excell 2013): “…while all laws require licensees to provide the government with information, most are silent on how the information should be shared and what the government should do with it.” For example (Veit and Excell 2013), “Uganda’s Petroleum Bill requires licensees to keep records of a wide range of information on the quantity and quality of crude oil reserves, discovery, and drilling operations, … Confidentiality clauses are unclear about who can access confidential information, how long information can be deemed confidential and how claims of confidentiality can be challenged in the public interest. By not clearly delineating what is considered confidential, legislation leaves government officials with considerable discretionary authority. Most laws incorporate harsh sanctions against the release of confidential information. Coupled with the ambiguity surrounding what is confidential, this creates a perverse incentive for officials to err on the side of withholding information.”

It should also be highlighted that most international oil companies are struggling to face the realities of being truly transparent about their revenues and profits on a project-by-project basis. The American Petroleum Institute is lobbying on behalf of its members (Chevron, Exxon, Shell, BP and all other major oil and gas companies, independents and service companies active in the U.S.) to seek annulment of project-by-project revenue reporting (as required by Sect. 1504 of the Dodd-Frank Act) in a legal case against the SEC rule (APR 2013). For tactical reasons companies would like to continue to be less transparent about the profitability of individual projects and prefer to stick to the current consolidated reporting of profits per country or region.

Renegotiation of Agreements

Governments who provide tax concessions in order to attract investments from natural resources extraction companies must be cautious not to offer excessive discounts. Renegotiation of contracts afterward is not always feasible. However, the government of Liberia [with and RGI of 62 (RWI 2013) and listed as EITI compliant (EITI 2013) but with a poor transparency of government budgets (Open Budget Index of 43 on a scale of 100; IBP 2012)] reviewed 105 concession agreements signed between 2003 and 2006. The reviews screened for fair value of the FEP stipulated in the concession agreements and concluded that 36 agreements should be canceled and 14 renegotiated (APR 2013). Renegotiation was carried out with international assistance and resulted in major changes to a significant number of concession agreements (Gajigo et al. 2012). Cases like these provide evidence for the need to develop better tools for establishing fair value in extraction projects in order to find a proper balance between government FEPs and profits for the extractive company.