natural resource wealth optimization: a review of fiscal ...€¦ · etize natural resource wealth...

Natural Resource Wealth Optimization: A Review of FiscalRegimes and Equitable Agreements for Petroleumand Mineral Extraction Projects

R. Weijermars1,2,3,4

Received 3 November 2014; accepted 17 December 2014Published online: 29 January 2015

This review highlights the challenges of fiscal system optimization considering both the hostgovernment and extraction company perspectives. Countries around the world face an arduoustask in determining the optimal fiscal system to maximize the capture of economic rents ofnatural resource extraction activities. The extraction industry is equally challenged to meetglobal commodity demand because the capital investments required for developing newhydrocarbon fields and ore mines are on the rise, while tax takes on extraction activities tend torise 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 benefitsof resources produced in one country to finance capital investments for future field developmentin another country. One viewpoint is that profits are expatriated to the detriment of the hostcountry and to the benefit of another country or the world supply chain as a whole. Anotherviewpoint is that all resource holders benefit because a foreign entity always starts in a newresourceholdingnationby investing in thedevelopmentof anoil fieldor solidmineralmineusingthe 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 geographicallocation, 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 distortioncould go both ways: either incentivize, attract and stimulate or des-incentivize, repel and deterresource development. Additional factors to consider are external uncertainties such as politicaland fiscal stability, sovereign risk and even local weather conditions (mostly in offshore andArctic petroleum operations). Governments must tax the upstream rents of petroleum andmineral resources, but not to the level that suppresses extraction activities.All stakeholderswantat least an equitable share of the profits. Defining what is equitable is a matter of intensivenegotiations, renegotiation of prior agreements and sometimes litigation and internationalarbitration. 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 utilityof geological resource endowments. For example, the offshore tax regime employed in the USpivots the trade-offs between fiscal incentives and long-term resource supply to ensure energysecurity. This review concludes with a call for further research.

KEY WORDS: Fiscal regimes, Oil and gas extraction projects, Mining projects, Equitable agreements.

INTRODUCTION

Higher mineral commodities prices have, for most of

the last decade, resulted in increased revenues and

benefits for governments, citizens, and mining com-

panies. However, higher prices have also heightened

1Harold Vance Department of Petroleum Engineering, Texas

A&M University, 3116 TAMU, 501 Richardson Building, Col-

lege Station TX 77843-3116, USA.2Department of Geoscience and Engineering, Delft University of

Technology, Stevinweg 1, 2628CN, Delft, The Netherlands.3Alboran Energy Strategy Consultants, Delft, The Netherlands.4To whom correspondence should be addressed; e-mail:

[email protected]; [email protected]

385

1520-7439/15/1200-0385/0 � 2015 International Association for Mathematical Geosciences

Natural Resources Research, Vol. 24, No. 4, December 2015 (� 2015)

DOI: 10.1007/s11053-014-9262-8

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the expectations of governments and citizens and

created a widespread perception that the recent

mining boom may have benefited extractive indus-

tries more than host nations. While this perception

was initially more prominent in developing countries,

it eventually spread to a number of developed

countries. This has led to some governments imple-

menting a range of fiscal measures, with varying

success, to address the real or perceived inequities in

the sharing of mining benefits. – Boubacar Bocoum,2013 Lead Mining Specialist, The World Bank

[quotation from foreword in How to Improve Tax

Administration and Collection Frameworks (Guj

et al. 2013)].

New hydrocarbons and solid mineral resourcesare continually needed and are brought into pro-duction to literally fuel the world�s macro-economicsystem. The race to meet accelerating growth in theglobal demand for petroleum and mineral resourceshas intensified in the 21st Century. While a generalmarket perception of natural resource abundanceprevailed in the 20th Century, another economicreality is emerging in the 21st Century. The risingdemand for fossil energy and minerals has caused afundamental shift away from a world economy basedon cheap and abundant natural resources. Naturalresource endowments that can be extracted with lowinvestments have largely been depleted. Newpetroleum and mineral discoveries are still made,but these are much more complex to develop andproduce. Liquid and solid mineral resources that areeasy cash cows for both the developers and ownershave become very scarce.

The dramatic shift in natural resource extrac-tion opportunities means that extraction companiesmust compete increasingly harder across the globeto gain access to concessions. In the past, countrieswith petroleum and mineral resources had to createfavorable investment incentives to ensure theywould attract experienced resource extraction com-panies. Today, the terms are generally becoming lessfavorable for the extraction companies with royaltiesand overall tax take being higher in new concessionareas (see subsection ‘‘Government EntitlementTrends’’). The leverage roles have reversed, andextraction companies must grudgingly accept thenew, less-favorable terms. Uncertainty about thelongevity and reliability of royalty and taxationregimes is a major concern for operators. Manyemerging natural resource-rich nations have beenquite successful in renegotiating progressively biggerprofit shares from their natural resource wealth

(examples given in subsection ‘‘Fiscal Trends andChallenges Ahead in the Upstream PetroleumBusiness’’ and subsection ‘‘Trends and ChallengesAhead in the Solid Mineral Mining Business’’).Although more equitably extraction agreements arewarranted, nations that overshoot toward dispro-portionate high taxation rates may harm optimalresource exploitation, effectively suppressing overallincome for the state (see examples given inAppendices 1 and 2).

In addition to the rising tax burden for extrac-tion companies (see subsection ‘‘Government Enti-tlement Trends’’), their costs for exploration,development and production have risen fast over thepast decade. For example, the capital expenditure(CAPEX) of petroleum projects per unit productionhas risen 450% over the period 1999–2012 (Weijer-mars et al. 2014). Likewise, mining of base metalslike copper has also seen steep increases of CAPEX(analyst reports). The remoteness and high geolog-ical complexity of the remaining petroleum reser-voirs and mineral deposits have lead to increasingcost of natural resource extraction technology. Asubstantial part of the operational profits retained bythe extractive companies immediately needs to bereinvested in new projects to replace depleted oiland gas assets (e.g., Weijermars 2011a, b) as well asany mineral assets (Wansink 2013). Because opera-tional profits need to be reinvested in new projectsrather than flow to shareholders, dividends are un-der pressure (e.g., Weijermars and Watson 2011).Petroleum and mineral extraction companies canfinance the costly development of new resourcesonly because crude oil and mineral prices haveescalated, and the mid-term and long-term trends ofcommodity prices need to remain high for produc-tion to remain steady (see subsection ‘‘Fiscal Trendsand Challenges Ahead in the Upstream PetroleumBusiness’’). Although commodity prices have star-ted to decline in the second half of 2014, prices arelikely to resume their rising trend when demandgrowth recovers from current slow down when theeconomic depression ends (e.g., discussion in sub-section ‘‘Fiscal Trends and Challenges Ahead in theUpstream Petroleum Business’’).

Undeterred by the rising cost, populationgrowth and economic development have increasedthe demand for natural resources by about 10% perdecade over the past 30 years (Fig. 1). The marketfor all extracted energy and mineral resources getstighter, which in addition to rising extraction costadds upward pressure on commodity prices. For

386 Weijermars

most fossil fuels and mineral commodities, pricesdeveloped steeply rising trends during the pastdecade (Fig. 2), driven by rising demand in emerg-ing economies (APR 2013). In the 21st Century,fossil energy and minerals resources have entered acommodity super-cycle that must power the eco-nomic growth of both the developed and emergingeconomies. A commodity super-cycle typically is a20-year boom period characterized by strong de-mand, in previous occurrences associated with mo-ments of rapid industrialization and urbanization(like for the United States in the 1890s and for Chinain the 2000s) where supply takes a long time tomatch that demand (Heap 2005; Erten and Ocampo2012; Canuto 2014). Once supply has caught up withdemand or demand slows, the price hike relaxes.

The recent decadal rise of commodity pricesfueled by the rise in global demand has benefitedboth producer revenues and government tax takes.Windfall earnings have rewarded the long-termshareholders; the market value of extraction com-panies has risen substantially over the past decade instep with revenue growth, which translates to capitalgains for the shareholders. In this review article, welook at the profitability of petroleum and mineralextraction projects from two different perspectives:(a) the extraction company as the resource devel-oper, and (b) the government as the resource hold-er. Monetization of petroleum and mineral resourcewealth should be based on auditable arguments for

profit sharing that demonstrably meet the businessinterests of both the operator and the resourceholder. The extraction corporation has an obligationto optimize shareholder returns to compensateshareholders for the investment risk taken. Thegovernment has an obligation to optimize incomefrom the nation�s natural resource endowment tosecure long-term wealth for its citizens. Good gov-ernance and sustainable petroleum and mineralextraction ethics require a fair balance which mustbe found between the interests of the two principalparties (resource developer and resource holder).

This review proceeds as follows. The second sec-tion (‘‘The Stakeholders of Natural ResourceAssets’’)determines the financial interests of the principalstakeholders involved with petroleum and mineralresource extraction projects. The third section (‘‘Eco-nomic Rent Capture by Resource Holders’’) reviewsthe dynamics of capturing economic rent from naturalresource extraction projects. The fourth section(‘‘OptimizationofFiscalRent Sharing’’) outlines somedetails related to optimization of the fiscal rent-sharingprocess. The fifth section (‘‘Taxation Trends’’) quan-tifies actual trends in total tax takes of natural resourceextraction projects. The sixth section (‘‘Good Gover-nance and Equitable Agreements’’) provides a state-of-the-art review of the current developments regard-ing good governance and equitable extraction agree-ments. The last two sections are ‘‘Discussion’’ and‘‘Conclusions’’, respectively.

Fig. 1. Growth of natural resource usage between 1980 and 2007 (Graph source: OECD 2011).

387Natural Resource Wealth Optimization

THE STAKEHOLDERS OF NATURALRESOURCE ASSETS

‘‘Exclusion of a company from the Fund reflects our

unwillingness to run an unacceptable risk of con-

tributing to grossly unethical conduct. The Council

on Ethics has concluded that Rio Tinto is directly

involved, through its participation in the Grasberg

mine in Indonesia, in the severe environmental

damage caused by that mining operation.’’ — Kristin

Halvorsen, Norwegian Minister of Finance. Rio

Tinto has been excluded from Norway�s SWF

investment portfolio.

Stakeholders

The license to explore, develop and operate oil,gas and/or mineral resources is granted to extractioncompanies by the Ministry of Petroleum and Min-erals or corresponding authorities like the Ministriesof Interior or Economic Affairs or PetroleumDirectorate. By granting the right to operate re-source owners monetize their natural resources. Atthe same time, the extraction of the resources leads

to depletion, which means resource owners musthave a plan to turn the proceeds of current extrac-tion into long-term wealth. Citizens are hoping thatthe state will secure long-term benefits for them suchas by the establishment of sovereign (natural re-source) wealth funds (SWFs). The proceeds of pro-duction of natural resources are transformed intocash for the national treasury by means of royalties,income tax and/or profit sharing via a productionsharing agreement (for details, see Appendices 1and 2). National tax authorities must capture eco-nomic rent by effective taxation, including a share ofwindfall profits. Private companies are after profitsand do not easily forfeit windfall profits.

Designing practical tools and methods to mon-etize natural resource wealth in an equitable fashionalso should consider the cost to the environment.This is an opportunity not to be missed. Until nowthe damage to the environment of the mining regionis commonly undercharged in taxation systems.Environmental damages due to inadequate minemanagement have already lead the exclusion ofmines from major funding sources (see quotation atthe beginning of this section). Where possible, one

Fig. 2. Onset of commodity super-cycle after year 2000 has inflated prices of all major minerals

(precious metals, base materials) as well as thermal coal, crude oil and natural gas (except for

natural gas in North America due to shale gas oversupply in a land-locked market without LNG

export terminals). Vertical scale gives relative index from 1980 to 2005, for which year all prices are

normalized at 100 (%). Prices from 1980 to 2005 are backward scaled as real prices (corrected for

inflation). Prices for 2005–2013 account for inflation. [Graph source: APR 2013, based on IMF

Commodity Prices and World Bank Global Economic Monitor].

388 Weijermars

should take into account the effects of mineralreplacement, in line with the 3Rs philosophy‘‘Reduce, Revise, Recycle,’’ proposed by the 2008Kobe 3R action plan (OECD 2011).

Global Trade

First, it may be useful to provide an inventory ofthe monetary value of world trade represented bypetroleum and mineral commodities. Table 1 com-piles the total values of the 2012 global trade inhydrocarbons versus solid minerals. The ratio oftheir respective annual export revenues is about 2 to1 (i.e., $1.9 trillion for hydrocarbons vs. $1.0 trillionfor mineral commodities).

In a world where the global economy is fueledby petroleum and mineral resources from an intri-cate web of supply lines, natural resource utilizationis closely monitored, provides subject for continuous

debate and merits further research. For example, thedaily transfer of cash from oil importers to oil-exporting nations may adversely impact consumersurplus of net importers and could hurt westerneconomies. Nations with mature economies associ-ated in the OECD currently hold only 10% of theworld�s total proved oil and gas reserves (EIA 2013).These same OECD countries currently consumeabout half of the world�s oil and gas production(53% of 2010 world oil production, Fig. 3a; 48% of2010 world gas production, Fig. 3b). A 2005 RANDstudy calculated that daily $2.2 billion flowed towardoil exporters (Bartis et al. 2005). At 2011 increasedglobal oil trade volumes and prices, oil importerstransferred about $5 billion per day to oil exporters,amounting to $1.8 trillion a year—a sum equivalentto nearly 3% of world GDP ($63.1 trillion in 2010,World Bank data). In western economies, the pres-sure of lost consumer surplus due to the progres-sively rising oil prices has risen. Further rises in thecost of oil will adversely impact consumer surplusand hurt western economies; IMF models suggestthat rising oil prices will slow down global GDP(Kumhof and Muir 2012, 2013).

GDP Dependency on Natural Resources

State dependency on fiscal income from geo-logical resources has been compiled for selectedcountries in Table 2 (based on work by Boadwayand Keen 2010). There are at least 15 nations wherepetroleum revenues represent more than 2/3rd ofthe government revenue. Furthermore, 5 countrieshave budgets drawing between 65 and 45% from oil,5 countries between 40 and 30% and 12 countriesbetween 29 and 10%. Altogether, 37 countries re-ceive substantial income from petroleum extractionprojects (Table 2). Notably, the US, in 2014 theworld�s largest producer of oil and gas (but withnegligible exports; e.g., Neff and Coleman, 2014),does not appear in Table 2. As one of the fewcountries where subsoil mineral resources are notconsidered public property (unless they are situatedon public lands, about 1/3 of U.S. hydrocarbonproduction), the U.S. federal tax income from up-stream oil and gas revenues in fiscal year 2012 was$9.7 billion (made up of royalties, $8.5 billion or87%; bonus bids, $947 million or 10%; and rentalfees, $272 million or 3%; GAO 2013). For the U.S.federal government, the oil and gas sector providesless than 0.5% of its annual tax revenue [$2.2 trillion

Table 1. World Petroleum and Mineral Trades (2012 data, from

UN Comtrade 2013)

Commodities Export value

million USD

A. Liquid minerals

Hydrocarbons

Crude oil 1,562,341

Natural gas 327,521

Propane and butane 53,385

Total hydrocarbons 1,943,247

B. Solid minerals

Coals

Coal 127,105

Coke 7,424

Briquettes, lignite, peat 3,802

Total coals 138,331

Ore concentrates

Iron 126,667

Copper 51,943

Nickel 9,949

Aluminum 14,012

Other base metals 30,865

Total ores 233,436

Metals

Gold 288,554

Silver, platinum 65,143

Copper 139,103

Nickel 19,744

Aluminum 106,273

Lead 5,984

Zinc 12,251

Tin 7,033

Other base metals 9,101

Total metals 653,186

Total solid minerals 1,024,953


in 2010, which draws its lion share from individualincome taxes and payroll taxes (82% in 2010), aminor share from corporate income taxes (9% in2010), and another 9% from excise taxes, estate andgift taxes, customs duties and miscellaneous receipts(TPC 2011)]. Even in an U.S. oil state like Texas, oiland gas production taxes constitute only 4.5% of thestate�s 2013 tax revenues; excluding the state�s Fed-eral income sources (TT 2014). Alaska is an excep-tion and depends for about half of its state taxrevenues on hydrocarbons and for about 90% whenexcluding Federal contributions (AID 2014). TheU.S. diversified economy means the hydrocarbonsector accounts for about 5% of U.S. GDP (aver-aged over the first decade of the 3rd Millennium;e.g., Ratner and Glover 2014).

A complementary survey of nations with sig-nificant revenue from mining activities shows thattheir dependency on fiscal revenue from mining ismuch lower as compared to that for nations withfiscal income from oil and gas. Global leader isBotswana, with government revenue for 44% basedon diamond taxes, but the remaining mineral-richcountries only source between 19 and 1% of theirfederal budget from mining taxes (Table 2).The global fiscal take from monetized petroleum

resources is clearly higher and more abundantlyapplied than from mineral resources.

Federal budgets which rely on substantialincome from natural resource extraction projectsmust act even-handed to balance their current costand income. Governments must know their futureearnings from the mineral resources to enable long-term budgeting. The federal budget may spend allmonetized mineral wealths, or save part of it for thefuture, and build a fiscal stabilization or buffer fund.Figure 4 shows how volatility in resource revenuesmust be smoothed by careful planning in any case.

Volatility of state income is affected by the typeof agreement between the state and the miningcompanies, as well as by the life cycle planning ofthe mines operating in the country. Resource-rich,low-income countries must be cautious in pacing themonetization of their geological resources, as well asensure that the most dedicated extraction companiesinvest in the development of valuable prospects(Collier 2010). Auctions may be part of the prospectprice discovery process (Collier 2010; Cramton2010), as is exemplified by the auction process forexploration licenses of U.S. offshore blocks (see‘‘Case Study: U.S. Federal Oil and Gas Royalty andTaxation’’ section in Appendix 2).

Fig. 3. Comparison of hydrocarbon demand in OECD and non-OECD nations. a World liquids demand development (in millions barrels

per day), according to three EIA oil price case scenarios. b World natural gas demand for the next 30 years (2010–2040). Source:

International Energy Outlook 2013 (EIA, 2013).

390 Weijermars

Sovereign Wealth Funds

Many nations have resorted to establishing anoil and/or mineral wealth fund, the main goal ofwhich is to save part of the natural resource incomefor future generations (Santiso 2008). An additionalaim is to guard the economy against inflation (thenatural resource curse) as a result of cash windfallfrom easy oil money or mineral rents (Sachs andWarner 1995; Humphreys et al. 2007; Brahmbhattet al. 2010). Inflation of prices (‘‘Dutch disease’’)

that could arise from excessive money pumped intothe national economy by mining revenues can bemitigated by creating a sovereign wealth fund(SWF). Table 3 lists the principal SWFs funded byrevenues from oil and gas resource extraction. Themajority of oil and gas wealth funds, a special formof sovereign wealth funds (Fig. 5a), are located innon-OECD nations in Asia and Middle East (withNorway accounting for all of Europe�s oil fundassets; Fig. 5b). As per January 2014, $6.1 trillion istied up globally in SWFs, split between $3.6 trillion

Table 2. Average annual budget percentage (2000–2007) from hydrocarbons and mineral taxation for selected countries [Source: Boadway

and Keen 2010; based on IMF staff calculations]

A. Petroleum budgets B. Mineral budgets

Oil revenue>66% of annual state budget Mineral revenue>66% of annual state budget

Iraq 97 None

Oman 83

Kuwait 79

Nigeria 78

Equatorial Guinea 77

Libya 77

Angola 76

Bahrain 74

Congo, Republic of 73

Algeria 72

Saudi Arabia 72

Yemen 72

Timor L�Este 70

UAE 69

Qatar 68

Oil revenue 65–45% of annual state budget Mineral revenue 44% of annual state budget

Iran 65 Botswana 44

Azerbaijan 59

Sudan 50

Venezuela 48

Turkmenistan 46

Oil revenue 40–30% of annual state budget

Syria 39 None

Trinidad & Tobago 38

Sao Tome and Principe 35

Mexico 34

Vietnam 31

Oil revenue 29–10% of annual state budget Mineral revenue 20–10% of annual state budget

Cameroon 27 Guinea 19

Chad 27 Chile 12

Kazakhstan 27

Indonesia 26 Mineral revenue 9–1% of annual state budget

Ecuador 25 Mongolia 9

Bolivia 24 Liberia 8

Russia 22 Namibia 8

Papua New Guinea 21 Peru 5

Mauritania 11 South Africa 2

Equatorial Guinea 10 Sierra Leone 1

Colombia 10 Jordan 1

Gabon 10


related to oil and gas wealth and $2.5 trillion relatedto minerals and (primarily) non-commodities (SWFInstitute 2014). The world�s major SWFs funded byoil and gas revenues (Table 3) are state-owned fundsdesignated (in principle) to provide a pension pro-vision for future generations.

Table 3 also reveals that several oil-producingnations have chosen to install a number of compet-ing oil funds (e.g., Kazakhstan, Russia, Saudi Ara-bia, and UAE-Abu Dhabi). However, not everynation with natural resource wealth has chosen for aSWF to compensate future generations for thedepletion and loss of its natural resources (Van derPloeg and Venables 2011; Van Wijnbergen 1984).Several OECD countries with significant oil and gasproduction rank among this category: Federal U.S.and the Netherlands are notable examples. Also,many emerging producers have only installed oilfunds after the Millennium turn: more than half ofthe SWFs listed in Table 3 are in this category.Nonetheless, the combined asset value of oil SWFs

Fig. 4. States with major income from mineral commodities

with volatile prices must strive to smooth public expenditure to

compensate low-income years with surplus from high-income

years. Budgetary discipline remains important as well as the

realization that mining income cannot be raised unfairly at the

expense of operators—this will kill the goose with the golden

eggs (graph source: RWI 2013).

Table 3. World major petroleum funds (SWF Institute 2014)

Country Name of SWF Asset value $ bill Inception year

Norway Government Pension Fund-Global 818 1990

Saudi Arabia SAMA Foreign Holdings 676 n/a

UAE-Abu Dhabi Abu Dhabi Investment Authority 627 1976

Kuwait Kuwait Investment Authority 386 1953

Qatar Qatar Investment Authority 170 2005

Russia National Welfare Fund 88 2008

Russia Reserve Fund 86 2008

Algeria Revenue Regulation Fund 77 2000

UAE-Dubai Investment Corporation of Dubai 70 2006

Kazakhstan Kazakhstan National Fund 69 2000

UAE-Abu Dhabi International Petroleum Investment Company 65 1984

Libya Libyan Investment Authority 65 2006

UAE-Abu Dhabi Mubadala Development Company 55 2002

Iran National Development Fund Iran 54 2011

US-Alaska Alaska Permanent Fund 47 1976

Brunei Brunei Investment Authority 40 1983

Azerbaijan State Oil Fund Azerbaijan 34 1999

US-Texas Texas Permanent School Fund 25 1854

Kazakhstan National Investment Corporation 20 2012

Iraq Development for Iraq 18 2003

US-New Mexico New Mexico State Investment Council 17 1958

Canada-Alberta Alberta�s Heritage Fund 16 1976

US-Texas Permanent University Fund 15 1876

East Timor Timor-Leste Petroleum Fund 15 2005

UAE-Federal Emirates Investment Authority 10 2007

Oman State General Reserve Fund 8 1980

Mexico Oil Revenue Stabilization Fund of Mexico 6 2000

Oman Oman Investment Fund 6 2000

Saudi Arabia Public Investment Fund 5 2008

Angola Fundo Soberano de Angola 5 2012

392 Weijermars

initiated since 2000 has accrued to $827 billion as perJanuary 2014. Table 3 does not include sovereign oilfunds holding asset values less than $1 billion (e.g.,Equatorial Guinea, Gabon, Ghana, Mauretania andVenezuela).

The relatively low value of mineral-relatedsovereign wealth funds as compared to the totalvalue of petroleum SWFs is striking; mineral SWFshave accumulated no more than $36 billion (as ofDecember 2013; Table 4). This is only 1% of thevalue retained in the world�s petroleum SWFs($3,605 billion; see compilation in Table 3). Mineralmining projects are generally taxed lower than

petroleum extraction projects (see section ‘‘Eco-nomic Rent Capture by Resource Holders’’). This iswhy nations generally earn less from mineral miningthan from oil and gas projects, which explains whySWFs based on petroleum revenues altogether hold100 times the asset value of the combined SWFs fedby mineral revenues only. The relative wealth heldin petroleum SWFs ($3.6 trillion) versus mineralSWFs ($0.036 trillion) suggests that mineral resourcerents accumulate much slower than hydrocarbonresource rents. An alternative view is that the re-source rents of petroleum and mineral projectsshould have comparable values. However, this

Table 3. continued


Trinidad & Tobago Heritage and Stabilization Fund 5 2000

US-Alabama Alabama Trust Fund 3 1985

US-North Dakota North Dakota Legacy Fund 1 2011

UAE-Ras Al Khaimah RAK Investment Authority 1 2005

US-Louisiana Louisiana Education Quality Trust Fund 1 1986

Nigeria Nigerian Sovereign Investment Authority 1 2011

Total 3,605

Fig. 5. Global statistics on sovereign wealth funds as per August 2013. a Historical funding sources

for SWFs. b Geographic spread of SWFs. Source: SWF Institute (2014).

Table 4. World mineral wealth funds (SWF Institute 2014)


Chile Social and Economic Stabilization Fund 15.2 2007

Chile Pension Reserve Fund 7.0 2006

Botswana Pula Fund 6.9 1994

US-Wyoming Permanent Wyoming Mineral Trust Fund 5.6 1974

Kiribati Revenue Equalization Reserve Fund 0.6 1956

Australia Western Australian Future Fund 0.3 2012

Mongolia Fiscal Stability Fund 0.3 2011

Total 35.9


cannot be conclusively assumed without furtherresearch. Although the values of global trade ofpetroleum and mineral resources have a ratio of 2:1(Table 2), they deliver tax revenues commensuratewith their global trade shares only if petroleum andmineral resources have more or less equal economicrents. The lower fiscal rents of mining projects ascompared to petroleum projects may have to dowith the fact that mineral royalty regimes for avariety of reasons are generally lower than onpetroleum projects and generally much less eco-nomically efficient than for petroleum (see subsec-tion ‘‘Taxation Benchmarks’’). In any case, a 100times lower economic rent for mineral resourceprojects suggested by the ratio of the values held inpetroleum SWFs and mineral SWFs could mean thattax takes from mining projects are either modest orinefficient (or both). Earlier studies highlightedmodest mineral taxation regimes prevail in Sweden,Western Australia, China, Argentina, Chile andZimbabwe (summarized in subsection ‘‘TaxationBenchmarks’’), and inefficient resource manage-ment practices are still endemic in several Africannations (see case studies summarized in subsection‘‘Moral Obligation’’).

The issue of how states ensure that proceeds ofnatural resource endowments are shared and usedwisely for long-term benefits of their citizensremains important. For example, Norway hasexcelled in converting its natural resource legacyinto liquid assets for future generations: based on itsSWF value of $818 billion and a cumulative oil andgas production of about 38.7 billion boe as per 31December 2013, one can conclude that for eachbarrel equivalent produced the nation has currentlysaved $21.13 as future wealth.5

Sovereign mineral wealth endowments can beeasily mismanaged. Chile has forfeited copper rev-enues in the past, until its tax reforms of 2006 (seeAppendix 1) and nearly simultaneous installment ofits two copper SWFs (Table 4). The share of mineralextraction projects remaining for States is intimatelyrelated to the division of monetized natural resourcewealth between extraction companies and the state.This position paper does not further discuss policiesand mechanisms for the internal distribution ofmineral wealth. Instead, the research focus is on theimportance of building equitable agreements be-tween the resource holder and resource develop-ment companies. Petroleum and mineral resourcesrepresent a segment of the world�s natural resourceswith the largest monetary value, giving rise to manydisputes (both legal and armed) and leavingnumerous questions about equitable wealth sharingunanswered. The needs for further research and theproposed methodology are outlined in this reviewpaper.

ECONOMIC RENT CAPTUREBY RESOURCE HOLDERS

‘‘When we build national capacity to understand

natural resource sectors better – in civil society as

well as government – we also build trust between

government, business and citizens. Better under-

standing will generate fairer contracts and more

equitable national strategies too. In turn, this creates

local ownership, longer-lasting contracts, and a better

investment climate. Satisfied local communities pose

less political risk. Mutually beneficial agreements are

the only ones that will stand the test of time.’’ – Kofi

A. Annan, 2013 Chair of the Africa Progress Panel

[quotation from foreword in ‘‘Equity from Extrac-

tives’’ (APR 2013)].

Economic Rent Capture by Fiscal Means

One of the objectives of an efficient tax systemis to ensure that exploration and production activi-ties will not be adversely impacted by any tax bur-den. Taxation under any fiscal regime should notcause distortion of economic rent, i.e., the valueoptimization efforts of mining industry should notleave mineral resources undeveloped in the grounddue to the tax burden (Guj 2012). Figure 6 showsthat the portion of resource rent may be very dif-ferent for different geological deposits even of thesame mineral. The rent may also vary over time, due

5 The cumulative production is based on 2014 data from the

Norwegian Petroleum Directorate (http://www.npd.no/en/Topics/

Resource-accounts-and–analysis/Temaartikler/Norwegian-shelf-

in-numbers-maps-and-figures/Petroleum-production/. Taxes from

production outside Norway—if any—are only a minor contribution

to the fund, as the Norwegian Government provides credit for taxes

paid to host countries in most cases. More rent has been captured

by the state than what is in the SWF, as transfers to the fund started

not until 1996 (although it was founded in 1990). The earlier

petroleum tax revenues were included in the economy and were

used to retire state debt. Other income accrued to the state from

general taxes on the supply industry and from other petroleum-

related activities, but did not go to the fund. Yearly transfers from

the fund to the state budget are modulated around the long-term

real rate of return on the fund according to the needs of the

economy. In good years, less is spent and in bad years a bit more

(personal communication, Sigurd Heiberg, 21 Feb 2014).

394 Weijermars

http://www.npd.no/en/Topics/Resource-accounts-and--analysis/Temaartikler/Norwegian-shelf-in-numbers-maps-and-figures/Petroleum-production/



to changes in commodity sales price and materialsupplier costs. Taxation mechanisms thereforeshould ideally account for the possible variations inresource rent values. One of the challenges in nat-ural resource taxation is that an efficient fiscal takeshould be proportional to economic rents (Guj2012).

Stiglitz (1996) stated that economic rent onnatural resources ‘‘is the difference between the pricethat is actually paid and the price that would have tobe paid in order for the good or service to be pro-duced.’’ He further states ‘‘Anyone who is in a po-sition to receive economic �rents� is fortunate indeed,because these rents are unrelated to effort.’’ The latterstatement could be nuanced by specifying that effortis the cost related to finding and producing the good.It is clear that no provision is made for attrition ofcorporate capital due to risk. A risk premium shouldbe charged as well, and replacement costs for findingand developing new resources after production havedepleted the company�s existing resources. The riskpremium is needed to ensure future continuity of thefirm�s business investments. Some authors have in-deed claimed that Ricardian rents (cf. Ricardo 1817)are negligible for mining projects (Adelman 1990;Tilton 2003), but this is counter to the rising cost forfinding new mines that hold economically producibleresources. Hotelling (1931) introduced the notionthat for production of mineral commodities, indeedproduction cost does not include opportunity costthat must account for the reduction of the availableresource, in other words, a replacement cost is due(today accounted for by depreciation, depletion andamortization, DD&A). Cordes (1995) defined eco-nomic rent more pragmatically as the differencebetween the existing market price for a commodity

and its opportunity cost. The latter cost is the min-imum acceptable compensation to the owners of thegoods or services are prepared to accept. Forpetroleum and mineral resources, the capture ofresource or economic rents may also be termed thefiscal rent-sharing process.

Natural Resource Uncertainty and the Valueof Information

One of the uncertainties in greenfield petro-leum and mineral extraction projects is that no oneknows initially what the economic rent on a specificoil field or mineral deposit could be. Companiesmust first make huge initial investments and pay forthe value of information to find out what—ifany—net present value might occur in their con-cessions. Agreements about natural wealth sharingare the result of a complex process involving biddingon licenses, negotiations on profit shares, royaltiesand taxation rates. Asymmetry of information oftengives favorable leverage to operators in the earlystages of exploration and development (Fig. 7).

Once the resources have been discovered andappraised, these become proved reserves. Forexample, the resource maturation process ofhydrocarbon reservoirs is a technically complexprocedure described as a work flow by PRMS(2011), as an accounting requirement by FASB(2010), and as a reporting plight by the SEC (2009).Only when hydrocarbons are proven and appraised,the prospects are said to have matured into esti-mated ultimate reserves. For mineral extractioncompanies, the mineral reserves are determined

Fig. 6. The portion of resource rent available for taxation de-

pends on the complexity and quality of the mineral resource and

extraction costs. Companies need normal profit to compensate

for risks and taxable rents will vary accordingly. (Source:

Adapted from Land 2010).

Fig. 7. Leverage in oil and gas development projects shifts from

operators to resource holders as time evolves.


following the JORC Code developed in cooperationwith the Committee for Mineral Reserves Interna-tional Reporting Standards (CRIRSCO). The JORCCode requires that documentation in ore reserves bebuilt under the direction of a so-called CompetentPerson, who underwrites the reserves estimation. ACompetent Person is a person who is a member orfellow of the Australasian Institute of Mining andMetallurgy and/or the Australian Institute of Geo-scientists with a minimum of 5 years experiencewhich is relevant to the style of mineralization andtype of deposit under consideration and the activitywhich that person is undertaking. The Russian andChinese ore reserves reporting codes have beenmapped against the CRIRSCO template frameworkwith the aim of bringing these codes closer to theJORC-based CRIRSCO template. As of the datethe present review was completed, the U.S. SEC hadnot yet agreed with the CRIRSCO template but theSME Reserves Working Group is trying to reach amutually agreeable position on ore reserves report-ing (SME 2014).

This study assumes that the resource matura-tion methodology is understood. For a petroleum ormineral extraction company to commit resources toa new project, a reservoir or mine model is devel-oped to establish the resource value (NPV, IRR andsensitivity of these KPIs to changes in commodityprices, extraction technology cost, facility costs,royalties and tax rates). The amount of resource thatcan be classified as economically recoverable fluc-tuates according to the aforementioned parameters.The quantity of proved reserves in mineral miningprojects is determined by cut-off grade analysis. Ifcommodity prices drop and royalties and tax burdenremain unchanged, then mined ore with a highermineral grade is required to meet the economic cut-off. For petroleum projects, the quality of the oil andgas needs to be higher (less sour gas and lower vis-cosity oil), and higher volumes in the reservoir arerequired to meet the economic hurdle rate whencommodity prices fall. The implication of fallingcommodity prices is that fewer fields with petroleumand mineral resources meet the minimum qualityrequirements for economic production. Provedreserves are impaired and asset values evaporate,reducing the NPV of the extraction project and theflow of tax revenues will diminish.

Once an extraction company has sunk capitalto acquire the value of information to delineatethe resource value, the resource holder commonlyattains more leverage on its side because the

delineated fixed asset is firmly located within itsjurisdiction (Fig. 7). Many of the Earth�s undevel-oped petroleum and mineral resources are located inemerging economies where foreign entities assumerisk by major investments in exploration, develop-ment and production of new mines. When the judi-cial system is weak and not impartial as is frequentlythe case in emerging economies, operators may havelittle means of recourse when prior concessionagreements are rescinded, royalties are renegotiatedand/or taxation rates change. With either weakinstitutions or strongly state-controlled judiciarysystems, earlier agreements may be easily replacedby new terms less favorable to the operators andmore favorable to the resource owner. Conse-quently, an important shift in leverage occurs overtime from operator to resource owner (Fig. 7). Inthe early stage, the resource owner tenders oppor-tunities and operators assume risk in return for po-tential profits while exploring to identify prospects.As exploration efforts progress, exploration costs forthe oil company are mounting. The benefit of con-tinued exploration in producing areas means thatuncertainty is progressively reduced, so that thevolume and value of the resources can be delineatedwith more certainty. At this stage, it becomestempting and often effective (when short-term gainis the only objective) for the resource owner to use(and sometimes abuse) judicial leverage to demanda more or less ‘‘reasonable’’ share of the discovery(Fig. 7). At present, improved transparency andaccountability about oil profits and revenues flowingto governments is high on the international agenda.There also is a renewed global call for equitableconcession agreements, which balance the interest ofboth the resource developer and the resource holderin fairness. The various initiatives that strive forimproved reporting of payments made by theextractive industry to governments are highlightedin section ‘‘Good Governance and EquitableAgreements’’.

Asymmetry in Knowledge, Judicial Leverageand Ethical Conduct

The development of petroleum and mineralresources often requires foreign capital, technologyand expertise. Governments may suffer from asym-metry of information about the quality and quantityof their natural resources, which are often betterunderstood by foreign entities specializing in the

396 Weijermars

exploration, development and extraction of theseresources. Such foreign entities are exposed to thefull risk of the project uncertainty, which meanstheir capital expenditure is at risk and the risk is notshared evenly between the operator and resourceowner. Failure to produce from a licensed regioncommonly results in a rescinding of the right to ex-plore further in favor of a new operator ready tocommit new resources on exploration to locate newreserves (which by definition are economicallyextractable resources).

It is a perfectly sensible policy for, and plightof, sovereign nations to try retaining most of thecapital gains extracted from their developed naturalresources. The moment a significant discovery ismade, operators are exposed to asymmetry in judi-cial leverage. Resource owners are increasinglysearching for arguments to succeed in renegotiatingof previously agreed terms to obtain a bigger shareof the project proceeds. Lack of reinvestment in theresource owning country can be interpreted as un-due expatriation of natural resource and owner�srent value, depriving future generations from thebenefits of such heritage.

Asset value expatriationmay be a concern in bothOECD countries and emerging economies that havelegacy fields and did not anticipate the full impact of along-term commitment to foreign and national oper-ators that now export the proceeds for reinvestmentelsewhere. There is currently no significant judicialleverage for resource endowment optimization inOECD countries that wish to adjust existing profit-sharing agreements. The present royalty and taxationagreements commonly do not include provisions foradditional taxation on extraordinary large fields thatcan be developed with relatively low cost. OECDcountries have relatively strong judicial systems andinstitutions, where operators can take recourse in caseof a dispute about terms of contract. This may explainwhy there are only few precedents of cases whereOECD nations have readjusted previously agreedterms of exploration and production agreements.Notably, the taxation rates on hydrocarbon extractionprojects in countries like the U.S. and Ireland are verylenient and rank far below the global median (see‘‘Case Study: U.S. Federal Oil and Gas Royalty andTaxation’’ section in Appendix 2).

In contrast, many emerging economies (non-OECD nations) have a history where governmentsskillfully renegotiated their share of assets to ensurethese deliver more returns for the resource ownerrather than for the operators. Emerging economies

commonly have judicial systems that are less likelyto rule in favor of foreign operators. Governmentrepresentatives use their leverage on the judicialinstitutions due to which they can dictate their pre-ferred terms of agreement. The lack of independent,impartial judicial recourse for operators gives suchresource owners ample space to succeed quickly onnew terms, more favorable for the resource owner.In non-OECD nations, these renegotiations aretypically for PSA�s and rarely for royalties and in-come tax. Examples are the pressure of governmentson operating consortia to relinquish part of theirshare to the government (or a legal representative).Examples of renegotiated petroleum agreements aregiven in ‘‘Case Study: Kazakhstan ProductionSharing Agreements’’ section in Appendix 2; forrenegotiation of mining agreements, see ‘‘Renego-tiation of Agreements’’ section in Appendix 3.

An additional risk to extraction companies istheir exposure to sovereign risk, which is brieflyhighlighted in sub-subsection ‘‘Sovereign Risk’’.

Prior Research

Literature studying the effectiveness of businessarrangements between oil companies and resourceholders is vast (e.g., Deacon 1994; Kunce et al. 2003;Opp 2008; Wolf 2009). The majority of existingagreements still use the traditional framework forcontracts, which does not provide for progressivetaxation schedules (i.e., rise in step with windfall oilprices, Stroebel and Van Benthem 2013). Progres-sive taxation has been discussed by Johnston (2008)and Lovas and Osmundsen (2009). Arguments sug-gested for explaining why deviation from suchincumbent practices is only slowly taking holdinclude: inexperience of governments (Amadi et al.2006), high cost and risk associated with developingand using different contract designs (Tirole 2009),reluctance on behalf of governments to signalunfavorable future conditions (Spier 1992) and fearto poison the investment climate (Waelde 2008).The possibility of certain countries becoming lessattractive for operators that risk their capitalinvestment is real because too high taxation burdenis an investment disincentive (Blake and Roberts2006). Additionally, company�s tend is to react toexcessive taxation by overstating costs (i.e., gold-plating), management fees and changers for leasedequipment (Lund 2009), as well as abusive transferpricing by shifting profits between tax jurisdictions


to reduce their tax burden (Engel and Fischer 2010).Prior research of mineral taxation can be roughlydivided into two main streams: one represents opti-mal taxation theory (perspective of the state) andanother the resource development theory using ore-grading and reservoir modeling (the extractiveindustry perspective). Detailed reviews coveringmuch of prior work are included in prior reviews(Garnaut and Clunies Ross 1983; Otto et al. 2006;Smith 2012a, b).

Previous research has mainly focused on findingsystematic trends in contractual arrangements farbeyond the specifics of individual case studies. Suchresearch is extremely useful and provides a firmfoundation for more detailed analysis. A next step isthe development of practical tools and methods thatquantify and visualize how an optimal balance canbe achieved between the specific economic interestsof both the natural resource holder and the resourcedeveloper (or consortium of operators) in a partic-ular setting. Such tools and methods must be basedon reality as demonstrated in individual case studies.This is the approach advocated in the presentreview. Although the edifice of prior research is vastand impressive, the extractive industry has advancedfast and continually needs new tools and methodsthat suit the changing business landscape. Theintegration of optimal taxation for the state andoptimized economic return for the operator requiresfurther research and practical solutions. The speed

and quality of decision-making are decisive for thesuccessful development of mineral resources, whichis relevant for both governments and operators. Thismeans field development plans and resource mone-tization speed need to be monitored and quantifysensitivity to uncertainties and risk real time, soadjustments can be made instantly when promptedby certain triggers. Ultimately, the values realizedfor company NPV and government fiscal policy verymuch depend on the quality of the knowledge inte-gration process (Fig. 8).

OPTIMIZATION OF FISCAL RENTSHARING

Higher net revenues are likely to result from:

- predictable fiscal/regulatory regimes (mini-

mal case-by-case negotiation of terms, low risk of

unilateral changes ex post facto)

- substantial sharing of risk by governments

(with resulting increase in private exploration and

subsequent production)

- high degree of transparency (with fewer

resulting opportunities for corruption/other leakages

to public sector agents). – George Anderson, 2006,

Former Deputy Minister of Natural Resources,

Canada (quote from a Seminar on Practical Feder-

alism focused on Iraq, 2-11 June 2006, Venice)

Fig. 8. Knowledge exchange paths surrounding the workflow paths of geological asset exploration

and development. The values realized for NPV (and retained profits) and FEP depend on the

quality of the knowledge integration process. (Source: Alboran Energy Strategy Consultants).

398 Weijermars

The strong leverage positions of resource own-ers may result in either equitable regulation (oper-ator risk mitigated and excess earnings regulated) orexpropriation (operator risk raised to 100% loss or afraction thereof) as two extreme examples ofincreased asset control by authorities of sovereignnations. We first discuss these two end members:risk-free, regulated resource delivery (subsection‘‘Regulation Versus Taxation’’) and expropriation(subsection ‘‘Expropriation’’). These two modelsmay help determine the conditions required for theoptimal natural resource development agreementswithin the broad spectrum of possible contractualarrangements. The ingredients for developing opti-mal contract arrangement are outlined in subsection‘‘Optimal Contract’’. Uncertainties and risks areaddressed in subsection ‘‘Quantifying Risk, FiscalTake and Economic Return for Operators’’ andsubsection ‘‘Quantifying Risk and Fair Royalties forPrivate Mineral Owners’’.

Regulation Versus Taxation

Regulation was introduced in utility services(water, gas, electricity, communications and othercommunal services) to avoid price collusion andextortion of excessive profits from dependable end-users who have no options for alternative suppliers.Regulation typical ly applies to the downstreamenergy industry (see later in this section). The up-stream energy industry and mineral extractioncompanies generally are free to compete providedthey pay taxes on the proceeds. The intention is tooptimize mutual benefits for both the operator andresource holder in a particular field developmentproject. This intention should ideally be reflected inthe agreement that specifies for that field the appli-cable rates for the company�s tax payments. Onecould argue that windfall tax, i.e., progressive taxa-tion that capitalizes a country�s take on excessprofits, is not unreasonable when striving to preservenatural resource wealth for future generations of anatural resource-rich nation.

Obviously, a key issue for a nation with naturalresources is to decide which type of contract is mostprofitable for its treasury. Although the contracts forpetroleum and development are more standardizedthan for mineral mining projects, both commoditysectors are subjected to a wide range of possiblefiscal regimes and regulation. The royalty andtaxation mechanisms for mineral and petroleum

upstream extraction projects are concisely explainedin Appendices 1 and 2, respectively.

Arguments in favor of royalty and taxationagreements (RTAs) and production sharing agree-ments (PSAs) as opposed to service contractagreements (SCA) are as follows. When companieshave incentives and capacity to boost field returns(IRR) for raising their corporate profits (ROCE) asis the case in RTAs and PSAs (but not in SCAs, see‘‘Service Contract Agreement (SCA)’’ sectionAppendix 2), they will automatically bring in morefiscal take for the government treasury. However,extreme project performance may trigger tensionbetween the extraction company and the hostcountry�s tax authorities. Highly profitable projectsshould make clear to the general public and resourceholder what wealth is generated for them by theresource extraction company. The public perceptionis that a nation�s geological legacy should generateaccountably benefits for its citizens instead of cre-ating a sense of disinheritance. Extraction compa-nies may benefit too, but economic rents should notbe unfairly expatriated, especially not by transferpricing. The least controversy is likely to occur forprojects that occupy a certain bandwidth in the IRRspectrum (Fig. 9). Highly unprofitable projects thatdo not leave margins for taxation and flagging abilityto generate profits (negative realizations trend;Fig. 9) may lead to hostile questions about the

Fig. 9. Companies are after high IRR projects to realize high

corporate ROCEs (vertical scale). Governments are after max-

imized FEP (horizontal scale). Instruments are taxation mech-

anisms (RTA, PSA, SCA) linked to production volume sales,

price floor regulation and profit caps. Source: Alboran Energy

Strategy Consultants.


expertise and capability of a mining company. Thisin turn may seriously undermine public trust in thegovernment�s ability to act as skilful custodians ofthe national petroleum and mineral resourceendowments. Ultimately, political instability mayensue, which increases the risk of harm to—andloss—of the petroleum and/or mineral assets. Equi-table agreements provide more stability in thelonger run for both the extractive industry as awhole and their prospective government partners.Mutually profitable operations are sustainable co-operations. Additional regulation is possible by (1)mitigation of downside risk for operators by a pricefloor for gas or oil wellhead sales (or for certain oregrades) to attract investors, (2) royalty relief suchas extended by the U.S. DOI to offshore operatorsin deep-water projects (see Appendix 1), and (3)profit capping (particular of windfall earnings) toavoid companies earning excessive project profits.Such excessive profits would leave the country ascash transfers for the benefit of the corporateROCE and the company shareholders, but deprivesfuture generations from the benefits of naturalresource wealth in the producing country. Exam-ples of price floor regulation of natural gas well-head prices have been discussed in Weijermars(2010a, 2011b).

In the downstream energy sector, regulationtypically allows energy utilities and transmissionnetwork companies to charge tariffs that pay onlyfor the cost of capital (WACC) required for main-taining their services. For example, U.S. and Euro-pean energy transmission companies are subject toboth federal and state regulatory agencies, allowingfor downstream energy utility services only withtariffs set at WACC level (Weijermars 2010b, c).This is justifiable, because there is little business riskin the captive consumer market of utilities. Somerisk premium in the WACC of utilities resides in thecost of equity capital and interest on debt capitalapproved by the regulatory authority. In some casesthe regulator may punish ineffective performanceand mandate tariffing below WACC level (e.g., seeexample of El Paso documented in Weijermars2012a). National oil companies that are under 100%state control (e.g., Saudi Aramco and National Ira-nian Oil Company) can be interpreted as entitieswhere the state regulates corporate earnings to thelevel required to cover services; all excess earningsflow to the state.

In the regions where the upstream energybusiness is liberalized, companies can commit to

develop fields where exploration risk, operationalrisk and investment risk are high. Difficult fields willonly be developed if return on capital investeddelivers an appropriate risk premium. Therefore, theheight of the risk premium is where a balance mustbe found between the business interests of thepetroleum or mining company, its investors and theresource holders. Only when governments provideguarantees against project failure, foreign companiesmay be prepared to refrain from charging the riskpremium. This would apply when price floor guar-antees protect companies against future revenue dipsdue to price volatility of natural gas (Weijermars2010a, 2011b). Project risk is reduced to zero for theservice providing company in the case of servicecontract agreements for field development (see‘‘Service Contract Agreement (SCA)’’ sectionAppendix 2). This contractual model for fielddevelopment resembles the regulated returns oninvestment of energy utilities. However, when com-plex deep-water assets or fields in the risky Arcticwaters need to be developed, attractive returns oninvestment will be necessary for companies to engagetheir expertise and resources to develop new tech-nologies required to execute such projects. This iswhy new models for optimization of ever morecomplex natural resource development projects areneeded, which should specify the cost and rate ofuncertainty reduction for inclusion in future resourcedevelopment agreements.

Expropriation

Regimes of countries that have GDPs highlydependable on oil income are often relying on costlywelfare programs, infrastructure development, taxexemptions and fuel subsidies to buy support fromtheir constituencies. The sovereign regimes mustbalance the risk of losing internal political supportagainst the risk of becoming less-attractive partnersfor foreign investors. If existing contracts are per-ceived as suboptimal by the resource holder and itsconstituency, and leverage is assumed high by them,expropriation may be the outcome. Expropriationsof field assets developed by foreign companies werecommon in the 1960s and 1970s, but were rare in theperiod 1980–2000. The struggle to retain full controlof company assets has intensified since the Millen-nium turn. Rising oil prices have made hydrocarbonassets more valuable than ever before, and resourceholders are tempted to wrestle for a bigger share of

400 Weijermars

the profits. Their ultimate measure is outright sei-zure of assets (e.g., Argentina, Bolivia, Ecuador andVenezuela) next to ‘‘partial’’ expropriations bychanging previously agreed government entitle-ments through use of excessive leverage on opera-tors by threat of fines and taxes (e.g., China, Russiaand Kazakhstan, see ‘‘Case Study: Kazakhstan Pro-duction Sharing Agreements’’ section Appendix 2).A recent study claimed that even with an optimalcontract expropriation may still occur (Stroebel andVan Benthem 2013), unlike earlier research reportswhich suggested expropriations will not occur inequilibrium contracts (Thomas and Worrall 1994;Ljungqvist and Sargent 2004). A similar assertion ofexpropriation in equilibrium contracts was elabo-rated in another study (Guriev et al. 2011) whereexpropriation could occur when foreign operatorresort to tax evasion even when the taxation regimeis reasonable or when rising oil prices lead to regreton the side of the resource holder about earlierroyalty and taxation tariffs. Other studies suggestthat expropriations are more likely to occur whenproject and company profits soar beyond a certainbenchmark (Aghion and Quesada 2010; Engel andFischer 2010; Rigobon 2010).

Optimal Contract

The past situations where resource holderswould suffer from lack of expertise and where con-tracts were mostly designed to encourage resourcedevelopment have become rarer as consultancy ser-vices have spread globally and knowledge for re-source development is more readily shared. This hasshifted the leverage from resource developers to re-source holders, but is not everywhere reflected in theconcession and licensing agreements (see subsection‘‘Moral Obligation’’ and Appendix 3). Like any rapidchange process, the transition faced by the globalcommodity markets is not necessarily going to besmooth. Resource holders and resource developersare now negotiating for the monetization of productsthat have become more valuable than ever before inhuman history (almost without exceptions). Theraised stakes make the decision-making processabout concession terms, royalties and taxation ratesmore demanding. The value of information has risen.Better tools need to be developed to aid finding a fairand neutral balance for optimal natural resourcedevelopment. Model solutions can help quantify andvisualize how an optimal balance can be achieved

Fig. 10. aOptimal tax rate (T*) maximizes fiscal NPV (cumulative taxes) for the government. A too high rate deters

mining activity, while too low rates deprive the treasury from a fair share of the mining profits derived from the

nation�s natural resource wealth. (Graph source: Tilton 2004). b, c Ratios of realized and unrealized NPV in a

mining project are affected by taxation burden and commodity price fluctuations. Case (b) occurs for low com-

modity prices, high tax rate or both. Case (c) occurs for high commodity prices, low tax rate or both. These static

cases shift back and forth over time as uncertainties evolve. Risk mitigation improves as value of information on ore

grade becomes better constrained. Source: Alboran Energy Strategy Consultants.


between the economic interests of both the naturalresource holder and the resource developer (orconsortium of operators). Improved models mustinclude tools and methods that can support futurenegotiations aimed at building equitable agreements.Such agreements should provision for fair sharing ofpetroleum and mineral resource wealth, and must bedemonstrably fair for both the extraction companyand the resource holder.

A traditional approach of tax optimizationsimply considered the trade-off between total fiscalNPV for the government (cumulative FEP) and thetax rate (Fig. 10a). This approach suggested thereexists an optimal tax rate (T*). There are severaldetailed mechanisms underlying tax optimization,where time value of money and volumetric rate ofmineral extraction play a crucial role. The modelshown in Figure 14a is useful but too simplistic as itdoes not account for such factors relevant to theappraisal of extraction projects. Therefore, a moreadvanced approach models tax optimization using amore complex (but still manageable) set of param-eters such as profit-making capacity of the operatorsand rate at which resource NPV is monetized for thegovernment�s treasury.

Figures 10b, c show the realized NPV shares ofthe mineral owners and government, as well as theunrealized part. The size of the realized NPV gen-erally grows over time as companies identify moreresources and monetize more of the resource byproduction. However, excessive taxes may reducethe operator NPV. Commodity price volatility isanother uncertainty that may either add NPV (whenprices rise) or erode NPV (when prices fall). Opti-mized agreements strive for equitable mineraldevelopment and extraction projects under condi-tions of uncertainty. Optimization of mineral wealthalso means the rate of NPV monetization shouldoccur at a rate that is optimal for the wealth creationprocess. Holding mineral resources in the grounduntil price rises occur in the future which is generallynot a profitable strategy as time value of moneyeasily beats the cyclicity of mineral commodity pri-ces (see Smith 2012a, b).

Quantifying Risk, Fiscal Take and Economic Returnfor Operators

Petroleum and mineral extraction projectsdeplete a nation�s mineral resources, for which thetreasury should be compensated with the means to

create long-term wealth. Extraction companieswhich explore, develop and produce the geologicalresource also must be rewarded for the risk taken.Companies are well equipped to develop the re-sources and assume a certain risk, where govern-ments usually cannot afford to take. However,companies become quite vulnerable to tax hikes orrenegotiations by the host government wheninvestments have been sunk into the development ofa mine complex (Vernon 1971). Once the asset hasbeen located and appraised, funds used to developthe asset are no longer mobile. A company cannoteasily withdraw from its operations when tax ratesbecome hostile, unless the asset can be sold at aprofitable price, which is unlikely when taxation af-fects the NPV of the petroleum asset or ore mine.Governments should not overlook that part of theoperational profits must reward companies for therisk taken. They might kill the goose with the goldeneggs if their fiscal policies become erratic (Weijer-mars and McCredie 2014a, b). On the other hand, ifcountries sell concessions too cheap, much of themineral wealth endowment is rescinded due to thestate�s misjudgments (see examples in ‘‘MoralObligation’’ section and ‘‘Case Study: ChileanCopper Mine Taxes’’ section in Appendix 1 and‘‘Renegotiation of Agreements’’ in Appendix 3).

Operators exposed to the business risk of amining project must maximize NPV and IRR forinvestors and skillfully assay the geological prospectsfor cut-off grade to reduce subsurface risk. Fiscalstability is a major concern in a decision to accept orreject a mine project. In a sense, risk for operatorstranslates to risk for the government. In bothpetroleum and mineral extraction projects, the risksremain high for operators even when initial opera-tions are profitable. Revenues are cyclical because ofvolatility in commodity prices related to economiccycles. When commodity prices fall, the NPV mayevaporate and the project IRR may bring the cor-porate ROI close to nil. Governments that applywindfall profits by sliding tax scales must also beprepared to consider fiscal regimes that allow for taxrebates when extraction operations turn unprofit-able. The negotiation room on the applicable taxregime must be used to find an optimal agreement;negotiation skills remain crucial (c.f., Radon 2007).

Figure 11a shows the annual rise and decline ofa short-term extraction project (typical for smalleroil fields, but not unlike small mining projects). Theoperator needs a project IRR that enables to com-pensate for the cost of capital (WACC) plus the

402 Weijermars

replacement cost for depleted resources and a riskpremium against inflation and long-term projectrisk. When a government raises taxes, either levieddirectly on the project (royalties, labor tax, asset taxetc.), or on corporate income (or both), then lessearnings from the revenue will remain for the com-pany. Figure 11b shows the annual net cash flow plusthe shares sliced by five specific taxes levied in a casestudy of a hypothetical taxation mechanism forMozambique (Daniel et al. 2010). Project NPV forthe company will tend to increase in high-riskcountries when projects are executed on time andwithin budget, because a higher discount rate wasinitially adopted to offset enhanced country risk.Higher discount rates also stimulate faster extrac-tion, because the IRR improves when the NPV is

realized in a shorter time (c.f., Boadway and Keen2010).

The risk for the company is that project earn-ings could turn marginal or negative when the IRRof the project�s realization dips below the discountrate assumed when the project was first approved.For example, the project NPV may evaporatewhenever the taxation burden rises. Subsurfaceuncertainties remain high and could undermine theanticipated success of the project when priorassessments of the resource volume and quality turnout to be too optimistic. Taxation income willdecline when the petroleum recovery factor or mineproductivity diminishes even after initial success. Ifgovernments want to encourage longer life cycles fora natural resource extraction project, lower taxationprovides more room for extension of the petroleumfield or mine life. The project overall success for theoperator is defined by ROI = IRR�WACC. TheIRR grows when the royalty rates shrinks becausethe project NPV will be higher for lower fiscal rates.Downward adjustments of the fiscal take when oil,gas or mineral resources near depletion can be apowerful fiscal stimulus that remains a relativelyunder-researched option. As the world is full ofaging petroleum field and mines, such research issignificant and may have global impact. The trend to‘‘ring-fence’’ profits from successful mines (see‘‘Fiscal Stability Agreements’’ section in Appendix1) is gaining popularity among resource-rich nations.However, indiscriminate application of ring-fencingcan be counter-productive for long-term develop-ment of mineral resources. Aging mines generallycan be kept open longer when proceeds of newermines are taxed jointly with the older mines ratherthan ring-fenced.

Fair Royalties for Private Mineral Owners

A relatively vulnerable group of natural re-source holders is the private mineral resourceholders. While often wealthy, private resourceowners are less likely to have access to the vastknowledge and resources that support governmentsand operators. Mineral resources belong to the statein many countries, but there are important excep-tions. Mineral rights pertain to a majority of nativeand private landowners in the U.S. are commonproperty of indigenous tribes in the NorthwestTerritories of Canada, and used to belong to certain

Fig. 11. a Monetization rate of NPV as represented by hypo-

thetical mineral extraction project (37 year life cycle). Revenues

flow only after incurrence of exploration and capital invest-

ments. Revenue-based taxation will be unsteady over the life

cycle of the mine, which may have optimal longevity if royalties

are lowered when production declines (adapted from RWI

2013). b Monetization rate of FEP by five tax mechanisms in a

case study for a hypothetical natural resource project in

Mozambique (source: Daniel et al. 2010).


common-law property owners in South Africa untilthe adoption of the Mineral and Petroleum Re-sources Development Act (MPRDA) of 2004.Common-law ownership of mineral rights by privateindividuals or companies applied to many of SouthAfrica�s rich mining regions, but the MPRDA nowstipulates royalties to be paid to both the common-law owners and the state (Otto et al. 2006). This is aunique case of partial expropriation, where the statecontrols the legislation but grants private mineral-ownership an opportunity to co-exist. Meanwhile,the higher royalty rates arising from new royaltiesdue to both the state and these due to pre-existingcommon-law contracts with private owners havelead to decline in mining activity and loss of jobopportunities in South Africa.

TAXATION TRENDS

In matters of mining taxation, governments rarely

believe that companies pay too much tax; companies

rarely believe that they pay too little tax; and citizens

rarely believe that they actually see tangible benefits

from the taxes that are paid.– Rashad-Rudolf Kald-

any, 2006 Director Oil, Gas, Mining and Chemicals

Department, The World Bank Group (quotation

from foreword in Otto et al. 2000).

This section defines royalties and fiscal entitle-ment payments (subsection ‘‘Royalties and FiscalEntitlement Payments’’), reviews the global spreadin taxation burden on petroleum and mineralextraction projects (subsection ‘‘Taxation Bench-marks’’), outlines how economic cycles imposeuncertainty on petroleum field and mine productiv-ity and briefly emphasizes the role of public per-ception in natural resource extraction agreements(subsection ‘‘Government Entitlement Trends’’).Throughout the below discourse, similarities anddifferences between petroleum extraction and min-eral mining projects are highlighted.

Royalties and Fiscal Entitlement Payments (FEP)

The term royalty enjoys a range of definitions andinterpretations. Perhaps the most useful definition of‘‘royalty’’ as applied to mining activities (Consiglieri2004) is ‘‘the charge incurred by companies forexploiting a resource that is property of the State.’’ It is acompensatory payment by the concessionaire to theState for the extraction of non-renewable natural

resources. It should seek (Gonzalez 2004) ‘‘reciprocityfor the reduction in natural capital resulting fromexploitation of non-renewable resources…’’ Accordingto another study ‘‘Royalty is not a tax but a payment tothe community for the purchase of non-renewableresources for the state’’ (Tasmania 2004). The chal-lenging issue often is to determine what reciprocitymeans when establishing the economic rent and a fairrisk premium for the risk taken (see ‘‘Optimization ofFiscal Rent Sharing’’ section).

It is clear from the above that in mining, royaltyand taxation are oftentimes used indistinctively. Thisis probably due to the fact that from the mineralproducer perspective, all duties are subtracted fromthe revenues of the company. From a fiscal per-spective, some effort is made to distinguish renttaxation at corporate level and royalties at projectperformance level, but the distinction remains arti-ficial and blurry. Royalty thus is used either sensustricto as a partial charge linked to granted rights(see Appendix 1) or sensu lato, which more or lessequates royalty to the overall tax take (i.e., royaltys.s. and other fiscal fees on the project, plus corpo-rate income tax). The ‘‘overall income tax’’ issometimes used as a surrogate for income tax plusall royalties and fees paid by the mine. The fiscaltake is defined here as the percentage of revenuefrom production sales after subtraction of resourcedevelopment cost and operating expenses; for theoperator remains cash from operations after tax.

In this study, the right to exploit a country�snatural resources is interpreted as granted by theresponsible sovereign authority in return for anagreement that details how the various project taxesplus corporate income tax add up to a total fiscalentitlement payment (FEP). The FEP is defined hereas the percentage of revenue from production salesafter subtraction of resource development cost(DD&A) and operating expenses (OPEX) (cf., Wei-jermars et al. 2014). FEP is made up of income tax,plus royalty charges, plus the government share ofproduction under any production sharing agreement(PSA). FEP is equivalent to the effective tax rate,which is the undiscounted value of all amounts paid tothe government, divided by the undiscounted value ofthe project�s cash flow before tax (Otto et al. 2000).

The FEP can be calculated as follows: FEP =(Equity Production9Revenue per unit production)�Operating Costs � DD&A � Net Income. Operat-ing costs include production expenses, SG&A andexploration expense, but not royalties or other pro-duction taxes. Equity production is the company�s

404 Weijermars

share of production prior to any government shareunder any PSA. Expressed as a percentage, FEP = 1� {Net Income/[(Equity Production 9 Revenue perunit production) � Operating Costs � DD&A]}.

For the operator remains cash from operationsas retained earnings after tax, the government�s fis-cal entitlement payment (FEP) can be termed totalfiscal take (Clint et al. 2013), government take (Bushand Johnston 1998), effective tax rate (Otto et al.2006) or average effective tax rate (IMF 2012).

Taxation Benchmarks

Appendix 1 gives a brief outline of the world�sprincipal mineral royalty and taxation rate mecha-nisms. These differ significantly from the taxation

mechanism commonly applied to petroleum pro-duction projects (see Appendix 2).

A review of taxation practices in a proprietarystudy of petroleum projects has shown a large spreadthat occurs across the globe (Clint et al. 2013). Themedian fiscal take for hydrocarbon projects is about70% of the revenues from production sales (aftersubtraction of resource development cost; Weijer-mars et al. 2014). Surprisingly, some of the lowestfiscal takes occur in western countries (like U.S.Gulf of Mexico, 45%, see ‘‘Case Study: U.S. FederalOil and Gas Royalty and Taxation’’ section inAppendix 2), while exceptionally high fiscal takesare commanded by taxation regimes of somedeveloping nations (like Algeria, up to 92%).

Table 5 also highlights that several OECD na-tions have some of the lowest fiscal takes for miningprojects (Sweden, Western Australia), but not all(Ontario-Canada). Poland is well above the medianfiscal take for mining projects with 49.6% fiscal take,but is in petroleum extraction royalties near thebottom end of the global range (Stroebel and vanBenthem 2013). Developing countries include manyhigh FEP jurisdictions, both in mining extraction(e.g., Cote d�Ivoire, Uzbekistan, Mongolia, Ghana;see Table 5) and in petroleum production projects(e.g., Algeria, Kazakhstan, see ‘‘Government Enti-tlement Trends’’).

Government Entitlement Trends

The right to exploit a country�s natural re-sources is granted by the responsible sovereignauthority to oil and gas producers in return for anagreement that details how the various project taxesplus corporate income tax add up to a total fiscaltake.

The upstream revenues from international oilmajors, independent operators and national oilcompanies are subject to a complex set of licensingfees, signing bonuses, royalties, production shareclaims and income taxes. Each country has its ownfiscal system for ensuring governments to receiveFEPs from natural resource extraction; for oil andgas taxation rates, see Ernst and Young (2013); formining royalties, see PWC (2012). The rates appliedto individual oil or gas fields in the portfolio of apetroleum company may differ even for assets lo-cated within the same country, because the negoti-ated government entitlement depends upon thespecifics agreed for each field on the date of last

Table 5. Average return on mining projects for investors (IRR)

and state (ETR or FEP) for a range of nations (Source: Otto

2004)

Country Foreign

investor�sinternal rate

of return (%)

Total effective

tax rate (%)

Lowest taxing quartile

Sweden 15.7 23.6

Western Australia 12.7 36.4

Chile 15.0 36.6

Zimba bwe 13.5 39.8

Argentina 13.9 40.0

China 12.7 41.7

Second lowest taxing quartile

Papua New Guinea (2002) 13.3 42.7

Bolivia 11.4 43.1

South Africa 13.5 45.0

Philippines 13.5 45.3

Indonesia (7th, COW) 12.5 46.1

Kazakhstan 12.9 46.1

Second highest taxing quarti

Peru (2003) 11.7 46.5

Tanzania 12.4 47.8

Poland 11.0 49.6

Arizona (U.S.) 12.6 49.9

Mexico 11.3 49.9

Greenland 13.0 50.2

Highest taxing quartile

Indonesia (non-COW) 11.2 52.2

Ghana 11.9 54.4

Mongolia (2003) 10.6 55.0

Uzbekistan 9.3 62.9

Cote d�lvoire 8.9 62.4

Ontario (Canada) 10.1 63.8

COW contract of work system


agreement signed. For example, Shell produces from37 different countries, which exposes it to govern-ment entitlements ranging from 32% in Ireland to97% in the UAE (Fig. 12a, b). The company�soverall retention of production revenues after sub-tracting DD&A and OPEX is about 30%, theremaining 70% is paid out to governments as FEPs.

The taxation mechanism for petroleum extrac-tion activities varies greatly per country, but threeprincipal types of contracts are commonly used:royalty and income tax agreements (RTAs), pro-duction sharing agreements (PSAs) and servicecontract agreement (SCAs). Appendix 2 gives abrief description and comparison of each type ofagreement. The majority of OECD countries useRTAs, while non-OECD countries mainly resort totailor-made PSAs (Johnston 2006). The SCA isstrictly a management fee arrangement and repre-sents less than 1% of the total number of agree-ments for oil and gas production (Sund and Hausken2012).

Countries with PSAs tend to take higher gov-ernment take (FEP = 69%) than countries withRTAs (FEP = 55%), according to a proprietaryreport by Clint et al. (2013). However, there is alarge spread of FEP rates in PSAs: Algeria andUAE have FEPs at the high end (up to 92 and 97%,respectively), and FEPs in legacy agreements withEgypt and Pakistan are mostly at the lower end(generally less than 50%). European oil majors havea range of different portfolio exposures to RTAs andPSAs (Fig. 13). For example, Eni has a relativelylarge part of its producing fields under PSAs (43%;mostly in African countries) and Shell has a rela-tively small exposure to production volumes underPSAs (14%). In spite of Eni�s large exposure toPSAs, the overall government FEP of its productionportfolio benefits from favorable agreements inPakistan, Lybia and Congo (Fig. 14a). As a result,Eni paid 67% of production sales after DD&A andOPEX to government FEPs in 2012 (Fig. 14b). Theranges of the fiscal entitlement percentages for the

Fig. 12. a Shell production portfolio with color bands indicating volume of production within a specific tax regime.

Production from low FEP concessions (less than 50% FEP) is at the bottom of the graph; top rates (e.g., FEP for

UAE is over 90%) are at the top. U.S. GoM is U.S. Gulf of Mexico. b Weighed average FEP (historic and forward

estimates (2013–2020) for Shell) is about 70% (black line), which is close to the average for the peer group (dashed)

of European oil majors (BG, BP, Eni, Galp, Shell, Repsol, TOTAL, Statoil) and within the spread (gray shade) for

that group. Source: Clint et al. (2013).

406 Weijermars

Fig. 14. Eni production portfolio with range of government FEPs. b Consolidated government FEPs paid by Eni for

production was 63% in 2000, climbed to 67% in 2012, and is expected to rise to 71% in 2020 due to most production

growth coming from high-tax jurisdictions (Angola, Kazakhstan) which is only slightly tempered by production

additions from low-tax jurisdictions (e.g., Mozambique with just 40% FEP). Source: Clint et al. (2013).

Fig. 13. Percentage of production volumes subject to FEPs specified in three types of contractual

agreement (PSA, RTA, SCA) as specified for each company. Source: Clint et al. (2013).


production portfolios of BP and TOTAL are givenin Figures 15 and 16.

It is instructive to examine the two Europeanoil companies with FEPs at, respectively, highest(Statoil) and lowest rates (BG). Statoil was bur-dened by a phenomenal FEP of 78% in 2000, whichreduced to 76% in 2012, and it is on track to furtherreduce its tax burden to 73% in 2020 (Fig. 17a). In2000, nearly all of Statoil�s production came fromNorway which applies a 78% FEP. In 2012, a hefty 3/4 of Statoil�s total entitlement production volumestill came from Norway. Statoil�s FEP will be low-ered due to internationalization with a heavy focuson low FEP production assets in its internationalE&P portfolio (Brazil, Canada, US) and only minorproduction volumes from high FEP jurisdictions(e.g., Algeria ).

BG has historically the lowest FEP of thepeer group of European majors with an averageportfolio FEP of just over 60% in 2000, whichincreased only to 63% in 2012 (Fig. 17b). BGproduction comes from countries with current

FEP rates of 60% (UK), 58% (Kazakhstan) and68% (Egypt), respectively. The bulk of BG�sproduction growth will come from Brazilian off-shore field development projects in the SantosBasin, for which the FEP is 65% [based on 10%royalties, 40% Special Participation Tax (SPT),and 34% corporate income tax]. This explainsBG�s low tax burden and average portfolio FEP of64% in 2020. The FEP summary for all companiesin the peer group of European majors is given inFig. 17c. For the European oil majors with globalproduction portfolios, the FEP tends to convergeon a median rate of 71% as we move toward 2020.

A data set maintained by WoodMackenzie,marketed as the Global Economic Model (GEM),contains fiscal details of 1,167 oil and gas fields from38 non-OPEC countries located in Europe, Africaand Asia. The database can be used to calculateFEPs for variable oil prices. The dataset publishedby Stroebel and Van Benthem (2013) was used hereto normalize government entitlements per countryBOED (based on 2007 production data, Fig. 18).

Fig. 15. a BP production spread over different tax regimes. b Consolidated government FEP paid by BP closely tracks

the peer group average. Source: Clint et al. (2013).

408 Weijermars

The traditional agreement between natural resourceholders and operators stipulates exchange of taxa-tion fees that rise linearly with oil price, due towhich most countries still have oil and gas produc-tion agreements that provision for government FEPsto increase linearly with oil price (Stroebel and VanBenthem 2013). However, a shift is signaled towardprogressive hydrocarbon taxes (Johnston 2008; Lo-vas and Osmundsen 2009). The median fiscal take onhydrocarbon production projects of about 70% issubstantially higher than in mineral extraction pro-jects (see below). This may also explain why petro-leum SWFs hold 100 times more value than mineralSWFs (see subsection ‘‘Sovereign Wealth Funds’’).The difference in fiscal take from petroleum andmineral extraction projects has not been investigatedin any great detail. IMF staff has noted before thatthe fiscal take on typical petroleum projects is higherthan on typical copper projects (Fig. 19). The sameconclusion was recently reinforced by new compar-ative tax analyses (IMF 2012).

The fiscal takes on mining projects, in a 2004benchmark of 20 nations, range between 28.6 and63.8% (Table 5). The arithmetic (un-weighted)mean value would be 45.7%, which is much lowerthan the 70% FEP on oil and gas projects. Produc-tion sharing agreements account for almost 50% ofall upstream oil and gas contracts, especially in non-OECD nations (Weijermars et al. 2014), but suchcontracts are rare in the mining sector.

This review proposes to use a vast array ofeconomic tools to design models that help quantifyhow an optimal balance can be achieved betweenthe economic interests of both the resource holderand the extraction company (or consortium ofoperators). A definition of the optimal contract willbe most meaningful if the objective functions of thecontractual parties are formulated and then weighedby stakeholder leverage and project risk exposure ofeach party. The optimal contract rightfully addressesrisk, opportunity and leverage for optimal wealth-sharing arrangements.

Fig. 16. TOTAL production across range of taxation regimes. b Consolidated government FEP paid by TOTAL

(solid line) is well above the peer group average (dashed) due to production from concessions with high FEP rates

(Angola, Nigeria, Russia, Norway). Source: Clint et al. (2013).


GOOD GOVERNANCE AND EQUITABLEAGREEMENTS

There are few areas of economic policy-making in

which the returns to good decisions are so high – and

the punishment of bad decisions so cruel – as in the

management of natural resource wealth. - DominiqueStrauss-Kahn, 2010 Managing Director, Interna-

tional Monetary Fund (quotation from foreword in

Daniel et al. 2010).

Decision makers involved with petroleum andmining revenues in government, extraction compa-nies and the investor community need informationon equitable agreements. Equitable means fair,

Fig. 17. a Consolidated government FEP paid by Statoil (solid line) is highest in the peer group of European oil

majors due to production from concessions with high FEP rates. b Consolidated government FEP paid by BG is

lowest in the peer group due to production from concessions with low FEP rates. c All FEP curves for European peer

group of oil majors. Source: Clint et al. (2013).

410 Weijermars

reasonable, unbiased, impartial, balanced just andright, according to a survey of common definitions indictionaries. The judgment of what is equitable is inthe eye of the beholder and can be quite subjective.Research on equitable extraction practices has beenstimulated from time to time by a range of institu-tions. Table 6 provides a non-exhaustive list ofselected institutions that have had various degrees ofengagement with sustainable extraction agreements,including research on wealth-sharing issues. The useof objective benchmarks and economic appraisal

methods is recommended to provide auditable eco-nomic appraisal arguments for equitable decision-making.

There are three solid arguments that supportstriving for equitable petroleum and mineralextraction agreements: (1) a moral obligation re-lated to sustainable governance principles, (2) miti-gation of long-term business risk and (3) responsiblemanagement of the reputation of the extractionindustry as a whole. The three arguments are inti-mately connected, as will be detailed below.

Moral Obligation

Moral obligations may easily be labeled bysome as too soft to have a real place in businessdealings, especially if short-term gains are favoredover long-term gains. But sustainable business gov-ernance requires building social networks and acorporate reputation of impeccable standing (Wei-jermars 2012b, c). Unfortunately, there are manypast and present examples where Fortune 500companies connected to mining have tarnishedreputations when it comes to equitable wealthsharing. Many of the world�s leading mining com-panies are OECD based, but non-OECD nations arerapidly becoming both the major exporters andconsumers of mineral resources. The economicmuscle of mineral commodity trading and miningcompanies is evident from Figure 20a, which showsthat Glencore�s 2012 revenue of $214 billion is morethan 6 times the combined GDP of Zambia ($19billion) and Congo ($16 billion). Glencore ranked12th on the Fortune Global 500 list of the world�slargest companies for 2013, and the company is lis-ted in London, Hong Kong and Johannesburg.

For context building, it is merited to brieflyreview a number of illustrative cases that highlightobscure and non-transparent business practices re-lated to major mining projects. Glencore, now theworld�s largest mineral trading and mining companyafter its 2013 merger with Xstrata, excels at creatingan intricate web of companies that undisputedlyobscure revenue flows, all which suggests a keeninterest in maintaining transfer pricing routes. Fig-ure 20b shows how Glencore�s controlling stake inZambia�s Mopani Copper Mine (MCM) is leveragedthrough a complex web of subsidiaries located inoffshore tax havens (Bermuda, Virgin Islands).Glencore holds a controlling stake in MCM throughCarlisa Investments—a company based in the

Fig. 18. Government FEP ($/boe from production sales after

DD&A and OPEX) vary greatly per country. FEP rises more or

less linearly with oil price below $80/barrel, and slope is steeper

at higher prices. Plot based on production data and FEP speci-

fied in Tables C2 and C3 of online Appendix to Stroebel and

Van Benthem (2013). Uncertainty spread in this plot may be

very high due to lack of independent validation of the proprie-

tary input data of WoodMackenzie.

Fig. 19. Comparison of FEP (vertical scale) in petroleum pro-

jects and mineral extraction projects (copper mines), using dis-

count rate of 15% (source: McPherson 2010; based on IMF staff

estimates for 2010).


British Virgin Islands owned in turn by GlencoreFinance (Bermuda).

In 2008, the Zambia Revenue Authority en-gaged an international tax accounting team (GrantThornton) to audit selected mining companies,including the Mopani Copper Mine (GT 2010). Theaudit report noted that MCM was selling copper toGlencore at prices far below the market value—apractice it labeled as plausible evidence for transfermispricing (GT 2010). Glencore hired Deloitteaccountancy to issue a letter stating that the auditstudy by Grant Thornton was flawed (DL 2011), and

issued a denial of any wrongdoing (Glencore 2011).Nonetheless, the European Investment Bank—anearlier lender to MCM—expressed ‘‘serious con-cerns about Glencore�s governance’’ (EIB 2011). Adecision was issued by the bank stating that ‘‘….dueto serious concerns about Glencore�s governancewhich have been brought to light recently and whichgo far beyond the Mopani investment, the Presidentof the EIB has instructed the services to decline anyfurther financing request from this company or one ofits subsidiaries’’ (EIB 2011). A separate studyclaimed that Zambia has lost over $4 billion between

Table 6. Selected organizations concerned with equitable resource extraction issues

Start Abbr. Full name Country (HQ city) Weblink

1930 & 1980 CMI Christian Michelsen Institute – Research for

Development and Justice

Norway (Bergen) http://www.cmi.no/

1970 MPRI/IDRC Mining Policy Research Initiative/International

Development Research Centre

Canada (Ottawa) http://www.idrc.ca/EN/

Pages/default.aspx

2001 ICMM International Council on Mining and Minerals UK (London) http://www.icmm.com

2002 Revenue

Watch Institute

Revenue Watch Institute US (New York) http://

www.revenuewatch.org/

2003 EITI Extractive Industries Transparency Initiative Norway (Oslo) http://eiti.org/

2005 African

Progress Panel

African Progress Panel Switzerland (Geneva) http://

www.africaprogresspanel.org/

2009 GOXI GOXI Global http://goxi.org/

2011 IM4DC International Mining for Development Centre Australia (Perth) http://im4dc.org/

2014 C-ENRD Center for Equitable Resource Development Global http://C-ENRD.org

Fig. 20. a Comparison of Glencore 2012 revenue and 20011 GDPs of Zambia and Congo (DRC). (Source: APR

2013, using World Development Indicators and GDP of the World Bank). b Cascading ownership structure of the

Mopani Copper Mine, Zambia (adapted from: APR 2013, using Mining Journal Online 2011 news on MCM).

412 Weijermars

http://www.cmi.no/

http://www.idrc.ca/EN/Pages/default.aspx

http://www.idrc.ca/EN/Pages/default.aspx

http://www.icmm.com

http://www.revenuewatch.org/

http://www.revenuewatch.org/

http://eiti.org/

http://www.africaprogresspanel.org/

http://www.africaprogresspanel.org/

http://goxi.org/

http://im4dc.org/

http://C-ENRD.org

2003 and 2007 due to corporate transfer pricingpractices (Standing and Hilson 2013). While it is notalways easy to prove fraudulent acts, ownershipstructures as in the case of Mopani�s concession donot improve transparency of business practices asaimed for by many recent initiatives (e.g., EITI2013).

Apart from Zambia, Glencore�s role in severalconcession deals in Congo (DRC) also has beenrather complicit. Figure 21 shows how Gecamines,Congo�s state mining company, held 25% of theKansuki mining concession until sold for $17 millionto Biko Investment Corporation in March 2011(DRC 2011). Biko is a 100% subsidiary of FleuretteProperties (British Virgin Islands), a companyowned by Dan Gertler, who is frequently quoted inbusiness alliances with Glencore. A World Bankreport (WB 2007) reviewed Congo�s three biggestmining contracts finding that the 2005 deals,including companies co-owned by Dan Gertler, wereapproved with ‘‘a complete lack of transparency’’(WB 2007). In 2010, the Kansuki mining concession

was 75 per cent owned by a company called KansukiInvestments SPRL and 25 per cent owned by Gec-amines (EITI 2010). The 25% stake held by Bikoinvestments would be worth $209 million accordingto a valuation by Deutsche Bank of the 37.5 perstake held by the Swiss commodities firm Glencorein Kansuki at $313 million (DB 2011). A separatevaluation by Bank of America corresponds to aneven higher value of $461 million (APR 2013). Thelowest valuation of the 25% Kansuki stake comesout at $133 million, which means the stake wasundervalued by at least $116 million (or up to $444million when using the Bank of America valuation)when Biko Investment purchased it for a mere $17million in 2011.

Glencore was also involved in the Mutandamine sale, another asset near the Kolwezi copperand cobalt belt, producing 87,000 tons of copper and8,500 tons of cobalt in 2012. In March 2011, SAM-REF Overseas (a Panama-registered company, half-owned by Glencore) had waived its right of firstrefusal on the purchase of Gecamines� separate 20%

Fig. 21. Transactions of Kansuki mine concession (Congo DRC) between Gec-

amines (DRC state company) and an array of offshore registered investment

companies (adapted from: APR 2013).


stake in the Mutanda project (APR 2013). Thiscleared the way for Rowny Assets (a British VirginIslands-listed company) to acquire the 20% stake forUS$120 million. The average of five commercialvaluations at the time of the sale put the value of the20% share in Mutanda at $634 million, implying a428 per cent profit for Rowny Assets (APR 2013).This revenue could have benefited the Congolesestate instead. While the relationship between RownyAssets and Glencore remains unclear, this examplehighlights both incompetence in the proper valua-tion and lack of oversight by the government ofCongo (DRC).

Above cases highlightedGlencore�s involvementwith opaque ownership structures. The presence ofoffshore-registered companies in the ownership chainlimits public disclosure requirements. Subsidiaries

and affiliates may act as conduits for intra-companytrade and creates extensive opportunities for trademispricing, aggressive tax planning and tax evasion,enabling companies to maximize the profit reportedin low-tax jurisdictions (APR 2013). Numerous min-ing companies other than Glencore are equally liablefor non-transparent governance. For example, themuch publicized tussle between Vale and Rio Tintofor ownership of Guinea�s Simandou iron ore deposithas been fraught with racketeering lawsuits involvingBenny Steinmetz Group Resources. The latter com-pany (HQ in Guernsey) is indirectly owned by Mr.Benny Steinmetz, who allegedly courts Guineangovernment representatives in ways reminiscent ofdealings by Mr. Gertler in Zambia (e.g., Economist2014). Another well-documented case of an under-valued sale of aCongolese coppermine is theKolweziconcession (Fig. 22). Four subsidiaries of CamroseResources, a company allegedly controlled by DanGertler (who courts favorable relationships withCongo�s government officials), bought from Gecam-ines in 2010 a 70% stake in the Kolwezi copper mineconcession for $60million (DRC 2010). Over the nexttwo years, the 70% stake was sold on to EurasianNatural Resources Corporation (ENRC), whicheffectively paid $685.75 million for Kolwezi andassociated concessions (APR 2013). The differencebetween the 2010 and 2012 values is well beyond anyreasonable increase in valuation that could beattributed to increases in the price of copper over thisperiod. The sales deprived the Congolese state(DRC) from a fair slice of its natural resourceendowment, with the 70% Kolwezi slice being

Fig. 22. Transactions of Kolwezi mine concession (Congo

DRC) between Gecamines (DRC state company) and an array

of offshore registered investment companies (adapted from:

APR 2013).

Fig. 23. Idealized cash flows with major revenues and costs

specified annually for a mine project with 38-year life cycle

(adapted from RWI 2013).

414 Weijermars

undervalued by at least $622 million when it was soldby Gecamines (Fig. 22).

It is fair to say that it takes two to tango (both in�good cop� and �bad cop� teams). The governmentrepresentatives of certain countries evidently act asinexperienced and/or unreliable custodians of thenation�s natural resource endowment. Research intoCongo�s mining deals has revealed the DRC treasurylost at least $1.36 billion between 2010 and 2012 onsales of vastly undervalued mining concessions (APR2013). The sum lost due to inadequate resourcestewardship by Congo (DRC) representatives wouldhave been sufficient to cover twice its total health andeducation budget (APR 2013). Proceeds from min-eral resource extraction should be auditable by bothtax authorities and regulatory agencies. However,when natural resources are vastly undervalued asdocumented above, this means that future genera-tions are unfairly deprived from the wealth that couldhave been derived from the equitablemonetization ofthe country�s natural resource endowment.

Mitigation of Long-Term Business Risk

Fiscal Risk

Once concessions have been acquired, stabilityof business operations in an extraction project de-pends in part on whether royalty schedules provisionfor a fair return for both the operator and the holderof the resource. Cash flows from petroleum andmineral extraction projects commonly have verylong life cycles, which is why careful appraisal of netpresent value (NPV) as impacted by tax burden overthe project life cycle is crucial for project success.Figure 23 shows a hypothetical case of mining rev-enues flowing steadily over three decades. This as-sumes that commodity price volatility remains eithernegligible or is skillfully hedged to offset any lossesfrom physical commodity sales by gains fromderivative trades. Excluding price volatility in thisway, it is easy to see that return from mining reve-nues may become volatile when the effective taxrates change at uncontrollable rates and at unpre-dictable times. This also brings immediately to theforefront why companies must strive for fiscal sta-bility, which requires impartial tools and methods toestablish what a fair tax rate mechanism is. Onlythen will it be possible to foster agreements formineral extraction that are mutually beneficial forboth the resource holder and the operator(s). The

reliability—and longevity—of the local tax regime isa key in the sensitivity analysis. An equitableagreement increases the likelihood of a stable taxregime and enables a more accurate valuation of theproject�s NPV, reducing the risk of project under-performance. Misappropriation and project failureare less likely to occur when the government take isequitable. Reversely, inequitable agreements createinstability that may lead to costly expropriations orrenegotiations which in the end drain resources fromall parties (except of the law firms). This can beavoided by getting an equitable deal right away,rather than later. In some nations, a fiscal stabilityagreement can help reduce fiscal risk for miningcompanies (see Appendix 1), but such agreementsare only likely to succeed if the profit of the mine isshared equitably between the operator and the state.

Sovereign Risk

Any risk arising on chances of a governmentfailing to make debt repayments or not honoring aloan agreement is a sovereign risk, according to mostdefinitions. The likelihood of sovereign default iscontinually monitored and benchmarked by themajor credit rating agencies. The potential risk offailure is determined by the likelihood of occurrenceand severity of the impact. What has emerged sincethe turn of the Millennium is that the financialstrengths of many emerging markets have signifi-cantly increased, and consequently their credit rat-ings have improved (Fig. 24a). At the same time, thesovereign credit ratings of many OECD nationshave deteriorated (Fig. 24b), particularly in thedeveloped markets which have been hit more se-verely by the Great Recession in the aftermath ofthe 2008 financial crisis.

The changes in the global landscape of sover-eign risk also indicate that many emerging nationsare reversing the former global asymmetry in accessto capital markets. Their interest payments on sov-ereign debt have come down. Many emerging na-tions have now become attractive investmentpartners, which has further reduced their depen-dency on any financial strength of the extractiveindustry. Extractive industry partners are neededdearly, but more for unique experience with theplanning, development and execution of large-scaleresource development projects rather than access tocapital markets. However, many nations with poorcredit rating but rich in natural resources (for


example, in Africa) remain deprived from low-interest rate debt financing and still depend on theirpartners from the extractive industry for access toequity, which means such resource holders haveweaker leverage in early negotiations.

Reputation of the Mining Industry

Good governance of the mining business haslately become a central issue on the international

agenda. The Extractive Industries TransparencyInitiative (EITI) launched about a decade ago(2003) now provides standards for how a country�snatural resources should be transparently governed,and calls for full disclosure of government revenuesfrom its extractive sectors (EITI 2013). Countriescan apply to become EITI compliant and implementthe standards for transparent governance of naturalresource extraction, including public accountabilityfor agreements and full disclosure of revenuestreams. The EITI International Secretariat based in

Fig. 24. a The sovereign credit ratings of many nations in emerging markets have risen since the

turn of the Millennium. (Time series for 2000–2012 moving from open-square symbols to solid dot).

bMany nations with the so-called developed economies have deteriorating credit ratings (S&P data

as of 31 December 2012, compiled by HSBC; https://www.emfunds.us.assetmanagement.hsbc.

com/investing-in-emerging-markets/content/developed-thinking-in-an-emerging-world.fs).

416 Weijermars

https://www.emfunds.us.assetmanagement.hsbc.com/investing-in-emerging-markets/content/developed-thinking-in-an-emerging-world.fs

https://www.emfunds.us.assetmanagement.hsbc.com/investing-in-emerging-markets/content/developed-thinking-in-an-emerging-world.fs

Oslo, Norway, develops the EITI standards in dialogwith stakeholder coalitions represented in the EITIBoard. A number of countries reviewed by the EITIBoard have lost their status as EITI compliant (e.g.,Congo–DRC, Equatorial Guinea, Gabon, Mada-gascar, Mauretania, Sierra Leone, Yemen; EITI2013).

In another development, U.S. congress passedin July 2010 the so-called Dodd-Frank Wall StreetReform and Consumer Protection Act. This land-mark legislation is partly aimed at bringing moretransparency into payments made by resourceextraction issuers (operators or their subsidiaries)to a foreign government for the purpose of com-mercial development of oil, natural gas or miner-als. Such payments require full disclosure (as perSect. 1504, U.S. Government 2010). The SEC hasadopted the final rules of the Dodd-Frank Act forimplementation of the legislation in 2012 (Kauf-mann and Penciakova 2012). Extractive industriesmust now in their annual reports disclose anypayment in excess of $100,000 on a project-by-project basis. The EU has initiated similarlegislation.

The Revenue Watch Institute (New York, US)is another organization that promotes the effective,transparent and accountable management of oil, gasand mineral resources for the public good. The Re-source Governance Index (RGI) evaluates four keycomponents of resource governance in each country:(1) institutional and legal setting, (2) reportingpractices, (3) safeguards and quality control, and (4)enabling environment. The 2013 RGI report findsonly 11 countries out of 58 countries (coveringnations producing 85% of world oil and gas) havesatisfactory standards of transparency and account-ability (RWI 2013). Countries deemed satisfactoryhave RGI scores above 70. These countries areNorway (98), U.S. (92), UK (88), Australia (85),Brazil (80), Mexico (77), Canada (76), Chile (75),Colombia (74), Trinidad and Tobago (74) and Peru(73). For comparison with EITI�s negative judgmentabout Gabon and Sierra Leone, these countries bothscore 46 out of 100 on the RGI scale, which is indeeddeemed weak by RGI standards (RWI 2013).Remember that both Gabon and Congo (DRC)have been de-listed by EITI, meaning these nationsare non-compliant with EITI standards (EITI 2013).

Clearly, governance of natural resource wealthis still weak in many nations, and there is ampleroom for improvement. The Revenue Watch Insti-tute rightly calls on governments to (RWI 2013)

� Disclose contracts signed with extractivecompanies.

� Ensure that regulatory agencies publishtimely, comprehensive reports on their oper-ations, including detailed revenue and projectinformation.

� Extend transparency and accountabilitystandards to state-owned companies andnatural resource funds.

� Make a concerted effort to control corrup-tion, improve the rule of law and guaranteerespect for civil and political rights, includinga free press.

� Accelerate the adoption of internationalreporting standards for governments andcompanies.

Many of the above initiatives focus onaccountability of governments, and the quality oftheir management and use of natural resourcewealth. The extractive industry itself will undoubt-edly come under closer scrutiny as well. Transferpricing has been a major attention area for theOECD, which has issued hefty volumes of guidelines(OECD 2010; PWC 2013). Additional discussion oftransfer pricing practices in mining projects is foundin Mullins (2010). The above developments highlightthat fair value agreements based on good gover-nance and sustainable mining ethics will becomeincreasingly important for the future success andcorporate reputation of mining companies. Thedevelopment of practical models, theory, tools andmethods is of invaluable importance for futurenegotiations aimed at building equitable agree-ments.

DISCUSSION

Relentless growth in the world�s population andits economic activities translate to a steep growth indemand for fossil energy and mineral supplies in theglobal trade system. The balance between demandand supply is maintained by the execution ofpetroleum and mineral extraction projects that mustbe profitable for investors to ensure continuedfunding of such activities. Countries around theworld must continually review and adjust theirpetroleum and mineral extraction policies and re-lated taxation regimes. A broad spectrum of inter-connected decisions and effects has been outlined inthis comprehensive review. The global agenda calls


for more transparency and accountability in themonetization of petroleum and mineral resources.Extractions of liquid petroleum and solid mineralsare two distinct sets of activities. Hybrid extractioncompanies that engage in both petroleum operationsand mineral mining are only few (e.g., BHP Billitonand Freeport McMoran). This review recognizes thedistinction between the two activities and high-lighted the common practices and critical differencesin terms of field development agreements andcommonly applied taxation mechanisms (Appendi-ces 1 and 2). Several major trends and challengesahead can be distinguished in the upstream petro-leum business (‘‘Fiscal Trends and ChallengesAhead in the Upstream Petroleum Business’’) andthe mineral extraction business (‘‘Trends and Chal-lenges Ahead in the Solid Mineral Mining Busi-ness’’). Challenges shared by the extractive industryand resource holders are separately highlighted in‘‘Need for Advanced Research’’ section.

Fiscal Trends and Challenges Ahead in theUpstream Petroleum Business

In the petroleum business, fiscal arrangementsand stability can be roughly divided into four groupsof countries: (1) those with stable RTAs, (2) thosewith stable PSAs, (3) those with unstable, renegoti-ated PSAs and (4) those with nationalized assets.

The first group includes most major OECDnations. The U.S. and all continental European

nations have relatively stable royalty and taxationsystems for long-lasting petroleum extractionagreements (RTAs, see ‘‘Royalty and TaxationAgreement (RTA)’’ section in Appendix 2). Forexample, the Groningen gas field in the Netherlandsis now over 50 years in production. The profit-sharing agreement between Exxon and Shell and theDutch State (Fig. 25) has been in place since first gasproduction started in 1963. Standard Oil (Exxon�sparent company) had entered the Dutch petroleumplay after World War II to form in 1947 the Ne-derlandse Aardolie Maatschappij (NAM), a 50/50joint venture between Shell and Standard�s Dutchsubsidiary Esso (Weijermars 2009; Weijermars andMadsen 2011). The giant Groningen gas field andassociated smaller gas fields field have generated forthe Dutch treasury �easy cash from gas� to a totalsum of 220 billion Euro as per January 2010 (Wei-jermars and Luthi 2011). However, no SWF wasinstalled.6

The second group is comprised non-OECDnations with stable PSAs. Such countries commonlyare smaller nations (e.g., Brunei, Oman and others)which prefer not to exert judicial leverage that mightdeter resource developers.

The third group of nations contrasts with thestable PSA environments and is made up by non-OECD nations that commonly resort to PSAs butconditions may be changed by them unchecked asweak legal institutions commonly are not indepen-dent from the state�s policy directives. Little or noresort remains for companies that see prior agree-ments rescinded without compelling justification.Examples are the shenanigans exerted by Kazakh-stan authorities on the partners in the Kashagan field(see brief case study in ‘‘Case Study: KazakhstanProduction Sharing Agreements’’ section Appendix2). Similarly, the struggle to strike a balance be-tween oil profits for the resource owner and assetdevelopers in Russia has been widely publicized.Nearly all major oil companies have flocked to se-cure and operate Russian oil and gas assets over the

Fig. 25. Profits from NAM are shared between Exxon, Shell,

and Dutch State at 30–30–40% according to the profit-sharing

agreement in Maatschap Groningen (after Weijermars and Lu-

thi 2011).

6 Unlike Norway, which created a Sovereign Wealth Fund (SWF)

from excess oil and gas earnings to protect its national economy

against inflation, the Netherlands has chosen not to install such a

SWF. Instead, gas income has been spent by the government over

the past half century, mostly as sunk cost into durable infrastruc-

ture, with the argument that such spending would cushion

inflation and future wealth would be generated by the improved

infrastructure. The debate to cure the Dutch Disease by creating a

belated ‘‘Netherlands SWF’’ continues until today (Wierts and

Schotten 2008).

418 Weijermars

past few decades. At Sakhalin I—the joint venturebetween ExxonMobil (30%), Sodeco (30%), ONGC(20%), Sakhalinmorneftegaz (11.5%) and Rosneft(8.5%)—Gazprom wants to sell Sakhalin�s gasdomestically at domestic Russian gas prices(McCredie and Weijermars 2011). However, theSakhalin I operator would prefer to sell its jointventure gas at premium export prices to the Asia–Pacific market, but this is apparently opposed by theKremlin. Meanwhile, at Sakhalin II—the joint ven-ture between Shell (55%), Mitsui (25%) and Mitsh-ubishi (20%)—a renegotiation of terms resulted inthe formal handover of operatorship to Gazprom in2008. The original partners received $7.45bn forsurrendering their 50% stake, which covered justtwo-thirds of the 50% share in expenditures alreadymade by the joint venture partners. Essentially this isan operational loss of 1/3 times 50% or 1/6th of thedevelopment cost, and a further 50% of the futureprofits were relinquished. The question remains‘‘How much wealth transfer by expatriation of profitsfrom a nation�s oil and gas resource wealth is rea-sonable?.’’ Ideally, international arbitration shouldbring clarity when such disputes arise, but more oftenthan not the oil companies decide to keep a lowprofile to avoid further sanctions.

The fourth group of nations comprises petro-leum resource owners who have nationalized com-

pany assets. These include mostly South Americancountries (e.g., Argentina, Bolivia, Ecuador andVenezuela; not discussed further here).

Because the majority of the remaining oil and gasresources are located in non-OECD nations, privatepetroleum companies will increasingly face difficultyin balancing the fiscal takes and government shares intheir project portfolios (see review in subsection‘‘Government Entitlement Trends’’). This in turnthreatens to affect the global balance between com-modity supply and demand and is likely to result in along-term upward trend in global oil and gas prices.

Oil and Gas Price Volatility

One of the challenges faced by the global oiland gas industry in partnership with resource ownersis dealing with the volatility in commodity prices.The issue of global energy prices is briefly addressed,focusing on the oil and gas price deck as determinedby the trend in cash cost, marginal cost and demanddestruction curve (Fig. 26). To augment and explainthe oil price deck mechanism, a brief example iswarranted. Between July and December 2014, theBrent price fell 50% (market data Bernstein Re-search). The Short-Term Energy Outlook by EIA(EIA 2014) affirms a lower price forecast for the

Fig. 26. Oil price deck for Brent oil. Cash cost (lower bound of price deck) is the

average operating expenditure required just to maintain production from existing

wells, treating development expenditure as sunk cost. Marginal cost (central curve

in price deck) is calculated using company�s estimated average cost of production,

including E&P majors and a sampling from small and microcap producers. Mar-

ginal cost will grow 3% year-over-year. The estimated curve of demand destruction

(DD, upper bound of price deck) is the oil price at which demand is negatively

affected by high prices, which occurs, for example, when consumers stop driving

due to high pump prices. Source: Bernstein Research.


short term: ‘‘EIA projects that Brent crude oil priceswill average $83/bbl in 2015…’’ Crude oil priceforecasts remain uncertain because of (1) the pos-sible range of potential supply responses from theOrganization of the Petroleum Exporting Countries(OPEC), particularly Saudi Arabia, and (2) the re-sponse of individual tight oil producers in the U.S. tothe new lower oil price environment. However, weassume that the global market, although sensitive tothe effects of OPEC quota decisions, is primarilydriven by the mean marginal cost of supply for theoil majors (lowermost curve in Fig. 26). The actualoil price is unlikely to venture either far or longbelow this marginal supply cost (estimated at about$70/bbl for 2015) because production would rapidlytighten due to non-OPEC suppliers delaying new oilfrom coming on-stream and the increasing likeli-hood of further constraints imposed by physicalstockpiling of oil supplies for speculative purposes.Although global GDP is sensitive to a hike in oilprices, most studies conclude that GDP growth is theprimary factor in driving demand and the time-averaged price of oil only to a lesser extent. From1980 till 2014, the elasticity of oil demand to GDP is1 (1% increase in oil demand occurs when GDPgrows 1%; personal comm., 11 Dec 2014 BernsteinResearch). Significant dips in oil prices, such as thenearly 50% drop in 1985–1986, lead to nearly 3%

demand increase (personal comm., 11 Dec 2014Bernstein Research), suggesting that the price elas-ticity of oil demand is 0.06, which means the 2014drop of 50% in the price of Brent may in fact triggera demand increase of 3%.

The price deck for natural gas in the threeprincipal world markets (North America, Europeand Asia) is determined by local contractual struc-tures and production cost (Fig. 27). Approval ofU.S. Congress for multiple LNG export terminalswill raise the U.S. gas wellhead price and likely re-sults in the convergence of global gas prices aboutEuropean contract values.

Trends and Challenges Ahead in the Solid MineralMining Business

In the mining business, fiscal arrangements andstability can be roughly divided into two majorgroups: (1) OECD countries with stable royalty re-gimes detailed and monitored by their respectiveagencies with mineral specific tariffs (e.g., US,Canada, Australia, Sweden), and (2) a large numberof countries with less well-defined fiscal policiessubject to serious governance concerns (includingmany African countries e.g., Gabon, Sierra Leone,Zambia, Congo DRC (see Good Governance andEquitable Agreements’’ section and Appendix 3).

Fig. 27. U.S. spot gas price is near cash cost of production. The European gas prices

(UK NBP, Euro Spot, Gazprom LTC, Norwegian oil-linked) are above marginal

cost. Japan�s LNG price is close to demand destruction as switch to alternatives

occurs as soon as is practical and economic. European market prices likely indicate

the level at which convergence of global gas markets occurs when global LNG trade

expands and brings liquidity in the world gas markets. Source: Bernstein Research.

420 Weijermars

The conduct of several major mining companiesis documented to a legacy of appalling ethics andpoor governance standards. Glencore and Rio Tintohave both been blacklisted by major investmentfunds such as the Norwegian SWF and the EuropeanInvestment Bank (see ‘‘The Stakeholders of NaturalResource Assets’’ section and ‘‘Good Governanceand Equitable Agreements’’ section). Fortunately,an increasing number of organizations (e.g., Ta-ble 6) strive for equitable agreements and docu-ments case studies to expose grave misconduct.Chile and Peru both represent countries where poorfiscal policies have now been replaced by muchmore effective taxation regimes (e.g., see ‘‘CaseStudy: Chilean Copper Mine Taxes’’ section inAppendix 1). But there is a long way to go in manynations (e.g., ‘‘Renegotiation of Agreements’’section in Appendix 3).

Need for Advanced Research

Examples of issues involved in the complexdecision-making process of establishing equitableextraction agreements are:

� Valuation of petroleum and mineral re-sources under various tax regimes

� Resource development optimization� Analysis of sensitivity to uncertainty and risk� Fair sharing of resource wealth� Long-term stability of extraction agreements� Design of templates for equitable profit-

sharing solutions

� Life cycle planning and economic cut-offgrade optimization

� Mitigation of resource loss due to high grad-ing in solid mineral mining

� Mitigation of stranded oil and gas in petro-leum extraction.

The value sharing process in natural resourcemonetization projects under conditions of opera-tional uncertainty (geological, technical, price risks) issubject to a range of taxation regimes that are eitherstable (mostly inOECDcountries, but not always andnot exclusively) or unstable (mostly in non-OECD,but with many exceptions). Research can providevaluable support for the decision-making process byavailing expertise and developing new tools andmethods for equitable extraction agreements. Thisreview is part of an on-going effort to establish aglobal research consortium (Weijermars 2014a, b).

Proposed Research Consortium

The Center for Equitable Natural ResourceDevelopment (C-ENRD) executes its programs inclose cooperation with carefully selected consortiummembers. The partner groups include stakeholders ofthe extractive industry, which comprises representa-tives from both the petroleum and mining business.Funding is anticipated from a growing number of pri-vate benefactors and organizations, including financialinstitutions, resource holders and the extractive indus-try.The researchprogramsofC-ENRDareexecuted incooperation with global knowledge partners from atleast five principal stakeholder groups (Fig. 28):

1. Government agencies of resource holders(such as resource taxation agencies) withexpertise of federal taxation mechanisms andagreements of FEP on a project-by-projectbasis.

2. Extraction industry comprised of petroleumand mining companies with data on projectappraisal and risks, reserve maturation andproduction history.

3. Research institutions (academia) with mod-eling expertise of resource appraisal underrisk and uncertainty.

4. Financial institutions, including sovereignwealth funds and global watchdogs like theIMF and World Bank with detailed bench-marks of the performance, contracts andFig. 28. Principal stakeholders of C-ENRD research programs.


fiscal regimes for oil, gas and mineralextraction projects.

5. Organizations developing standards forequitable wealth sharing and transparency ingovernance of wealth from natural resourceextraction.

The C-ENRD research proposals are screenedto help funding graduate students (MS & PhDs),post-docs and research scientists.

CONCLUSIONS

This review highlights the worldwide challengesof fiscal system optimization from both the hostgovernment and extraction company perspectives. Akey question remains ‘‘What is a fair taxation regimefor natural resource extraction in a particular geo-logical setting and a given geographical location?’’One must account for subsurface uncertainties aboutthe quality and volume of the resources and factor ininfrastructure needs and proximity to the world�smajor markets and trade centers. Additional factorsto consider are external uncertainties such as polit-ical and fiscal stability, sovereign risk and even localweather conditions (mostly in offshore and Arcticpetroleum operations). All stakeholders want atleast an equitable share of the profits. Defining whatis an equitable partition between normal profit andeconomic rent commonly involves intensive negoti-ations, renegotiation of prior agreements andsometimes litigation and international arbitration.

This review aims to provide a basis for a majorresearch initiative dedicated to design model solu-tions that can help quantify and visualize how anoptimal balance can be achieved between the eco-nomic interests of both the mineral resource holderand the resource developer (or consortium of oper-ators).

Macroscopic analysis can help optimize resourcedevelopment planning. The global research initia-tive of C-ENRD aims to provide relevant expertiseand knowledge transfer on country and regionalscales. As a starting point, we review the resourceexploration, development and exploitation processthat must progressively establish the net presentvalue of a specific geological resource. We thenanalyze the anticipated profits against the assumedrisk, adjusted cost of capital and the reservesreplacement cost for operators. This analysis is thenexpanded to determine models for establishing

reasonable profit-sharing terms between resourcedeveloper and resource holder. Finally, such modelswill be used to establish which type of contractcould strike a fair balance between risk and oppor-tunities under uncertainty for both the field operatorand the resource holder. Each set of assets brings itsown unique risk profile. Our case studies compriseexamples covering a wide variety of assets andassociated uncertainties and risks.

ACKNOWLEDGMENTS

Thoughtful comments by the reviewers andcurrent editor-in-chief of the journal, Dr. JohnCarranza, greatly helped to streamline thisreview—all their suggestions for improvement aremuch appreciated. Some seed funding was providedby Alboran Energy Strategy Consultants. This cov-ered the time to develop this proposal, cost of theformal registration and development of C-EN-RD.org. Bernstein Research (UK) is gratefullythanked for the generous provision of some of thedata used in this review.

APPENDIX 1: BRIEF OUTLINEOF MINERAL ROYALTY AND TAXATIONRATE MECHANISMS

The range of mineral royalties and taxation ratemechanisms in the mining sector is briefly outlinedbelow. The review shows that in rem taxation sys-tems tend to provide steady revenues for the trea-sury as long as a mine delivers plateau productionvolumes, but no share in any windfall profits due torising commodity prices. In personam taxation sys-tems are better suited when the treasury would wanta share in windfall profits. The trade-offs betweenshort-term cyclical gains and long-term success mustbe carefully considered in mining agreements. Min-ing projects remain sensitive to cyclical commodityprices which may affect mine longevity as dictatedby cut-off grade analysis.

Mining Royalty Systems

The below review of mineral royalties and tax-ation rate mechanisms in the mining sector draws

422 Weijermars

extensively from previous studies (Otto et al. 2006;Harman and Guj 2006; ICMM 2009; Land 2010;PWC 2007, 2012; IMF 2012; Smith 2012a, b; Gujet al. 2013).

Otto et al. (2006) concluded that the geological,economic, social and political circumstances of eachnation are unique, due to which royalty taxing is noone size fits all mechanism, but must be tailor-madeto be optimal for each specific case. A recent sum-mary of mining taxation by PWC (2012) stated that‘‘major challenges often lie in the administration ofthe rules and regulations by the tax authorities, ra-ther than in the legislation itself.’’ Various aspects oftax administration efficiency have been discussed inseveral recent studies (Collier et al. 2009; Calder2010a, b; Guj et al. 2013).

Nations with weaker tax compliance and poorlydeveloped tax administration tend to apply taxesbased on revenue value-based (ad valorem) or pro-duction unit-based royalties (both are so-called Inrem tax systems). Table 7 provides generic examplesof the various types of In rem and In personam taxes.In addition, there may be in kind benefits such asinfrastructure investments and social projects. Unit-based royalties may discriminate between scales ofoperators, with larger operations subjected to stee-per royalties, while family or cooperative run oper-ations pay lower rates. Some of the taxes indicatedin Table 7 are less current as discussed in detail inOtto et al. (2006).

Effects of Mineral Taxation Policies

The amount of mining revenues that could betaxed away (Fig. 29) generally aims to capture partof the economic rent. Nations with well-developedtax administrations tend to use profit-based andcapital gains-based mining tax systems (in personamtaxes). Profit-based taxes do not lower the eco-nomically recoverable quantity of resources (q* inFig. 29). For example, most Canadian Provinces useprofit-based mining taxation, as well as Nevada inthe U.S. and the Northern Territory in Australia.Based on corporate income tax, the share of profitstaxed is 35% in U.S. and Chile, 30% in Australia,Indonesia, Papua New Guinea and Zambia, 28% inMexico and South Africa, and 22% in Canada (2008rates; in Hogan and Goldsworthy 2010). In perso-nam taxes require a general level of tax complianceand a tax authority with administrative capabilitythat will perform audits when needed. The tax sys-

tem must be judicially well-developed and well-understood to enable compliance by operators.

Figure 30 shows the effect of revenue-basedroyalty, which lowers the total recovered resourcequantity (qadv in Fig. 30), because the economic cut-off grade needs to be higher, to pay for marginalextraction nearer the end of the mine�s life. The so-called high grading is stimulated by revenue-basedtaxes (an in rem tax mechanism). Revenue-basedroyalties (Ad valorem royalties of in rem tax type)are applied in Western Australia (7.5% of the real-ized sales value of crushed ore, 5% for concentrateand 2.5% for metals). Botswana used at some stageuniform royalty rates at 10% for revenues fromprecious stones, 5% of precious metals an 3% onother minerals. The ‘‘royalty value’’ is commonlydefined as ‘‘sale value receivable at the mine gate inan arm�s length transaction without discounts, com-mission or deduction for the mineral or mineralproduct on disposal.’’ The royalty value is a marketvalue that may be tied to a reference price from amineral exchange.

When revenue-based royalties are levied irre-spective of profitability, a proportion of the previ-ously economic grade will be lost to impairment.Such royalties continue to flow even when a drop inthe commodity price temporarily renders a mineunprofitable. If this scenario develops, lowering theroyalty may keep a mine profitable thus longer ac-tive for a certain cut-off grade. A lowered royaltymay lengthen the life cycle of a mine, assumingoptimal cut-off grade can be maintained. This willalso keep royalties flowing longer and therefore mayresult in a larger cumulative government take.

Revenue-based and unit-based royalties candestruct value for both the operator and the re-source holder, unless rebate clauses are built into themineral taxation system. Commodity prices nearlyalways drop during an economic recession because aglobal GDP contraction generally results in cutbacksof construction and production activities. Reversely,GDP growth of about 3% is commonly accompa-nied by construction booms with increased industrialoutput by as much as 10%, leading to rapid pricehikes in building aggregates and other mineralcommodities. Mining profits grow when global GDPspurts, but shrink when recessions hit the market.Cut-off grade analysis is required to adjust themining plan accordingly.

For industrial minerals, unit-based royalties arethe 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 thesmelter. The taxable value of NSR is based on thevalue of smelter concentrate volume produced, ad-justed for certain allowable costs incurred. Figure 31shows the effect of a combination of ad valoremroyalty and income-based taxation. In the mixedtaxation schedule, the ad valorem part lowers thetotal recovered resource quantity (qmix in Fig. 3a,

which equals qadv in Fig. 30), because the economiccut-off grade again needs to be higher, to pay formarginal extraction when the end of the mine lifenears. The ideal solution of a non-distorting tax iscertainly not achieved by unit-based royalty and to alesser extent by ad valorem ones. However, thereare important practical arguments for unit-basedtaxation in some jurisdictions with weak institutions.

Fig. 29. Ultimate recoverable reserves for risk neutral devel-

opment scenario is qRN. Risk premium reduces the cut-off grade

to q*. The commodity reference price on the world market is

assumed at PW. The risk-adjusted commodity production supply

curve is given by SRA, and risk neutral supply curve would be

SRN. (Graph source: Hogan and Goldsworthy 2010).

Fig. 30. Ultimate recovered resource volume under ad valorem

revenue-based royalty schedule is given by qADV. Royalty rev-

enue slice is the taxed fraction of revenues PW qADV, which

lowers the local net revenue price for the producer relative to

the world market by (1� tADV)PW. (Graph source: Hogan and

Goldsworthy 2010).

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

Tax type Basis

In rem taxes (unit or value based)

Unit-based royalty Set charge per unit

Ad valorem-based royalty % of mineral�s value (definition of value may vary)

Sales and excise tax % of value of sales

Property or capital tax % of value of property or capital

Import duty % of value of imports (usually)

Export duty % of value of exports

Withholding on remitted loan interest % of loan interest value

Withholding on imported services % of value of services

Value-added tax % of the value of the good or service

Registration fees Set charge per registration event

Rent or usage fees Set charge per unit area

Stamp tax Set charge per transaction or % of value of the transaction

In personam taxes (net revenue based)

Income tax % of income

Capital gains tax % of profit on disposal of capital assets

Additional profits tax % of additional profits

Excess Drofits tax % of excess Drofits

Net profits royalty or net value royalty % of mineral�s value less allowable costs

Withholding on remitted profits or dividends % of remitted value

424 Weijermars

Adopting an Appropriate Taxation Regime

Countries must carefully weigh their optionsand set mineral extraction taxation at appropriatelevels to ensure (1) attractiveness for investors and(2) retention of an equitable share in return onnatural resource depleted by the extraction process.The choice between in rem and in personam taxsystems is an important one. Nations like U.S. andSweden do not charge any federal royalties onmining, and exclusively rely on federal income taxesfor offshore concessions supplemented by auctionpremia and production share royalties. In some U.S.states, additional profit-based taxes are imposed(e.g., Nevada). Some countries with relatively weaktax administrations and poor compliance with taxa-tion rules (like Chile, Peru, Mexico) have also for-saken mining royalties. In the case of Chile, miningroyalties were finally introduced in 2006, which havesince corrected the country�s historic lack of mineralwealth sharing. The earlier rescinding of Chile�scopper wealth remains an important example of pastgovernment policies that forfeited a significant partof the nation�s mineral wealth legacy (see case studyin ‘‘Case Study: Chilean Copper Mine Taxes’’ sec-tion in Appendix 1). The country is now catching upwith mineral wealth value accrual in its copperSWFs (Table 4, main text).

In Angola and China, royalties are negotiatedby government representatives on a mine-by-minebasis so that rates are balanced to fit the uniquefeatures of the mineral prospect targeted for devel-opment. 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 advalorem royalty on copper commonly apply ratesbetween 1 and 4%. The reason is that unit-basedpayments are steady, while profit-based remittancesmay see years with no tax payments due to lack ofprofits. Although the administrative burden forgovernments seems lower for unit and ad valoremroyalties than for profit-based systems, the in remtaxes need to be periodically reviewed, indexed andadjusted in order not to move out of line withinflation rate and global commodity price cycles.Royalty revisions may be prudent when rates havebecome disproportionate (too low or too high), orwhen a new commodity is to be mined.

A comparative analysis by John Stermole ofunit-based, ad valorem-based and profit-based roy-alty systems is given in Table 8. This sets the raterequired for a government to receive annually thesame fixed amount of tax income ($20 million in thiscase). It follows that the percentages range between1.17 and 4.91%; the unit-based rate is a fixed valueper weight unit produced.

One could say that profit-based taxation with-out royalties is adequate for nations where majormining companies are incorporated in the samecountry, in which case most profits are ultimatelyreinvested in the country (and not expatriated). Thissituation also requires a well-developed tax admin-istration. In developing nations, mining profits arecommonly expatriated by foreign operators. In suchcases, unit-based and/or ad valorem royalties pro-vide a sure base income for the State, but also leadto high grading, leaving low-grade resources unre-covered. An important reason for forsaking profit-based taxation is that profits are commonly ac-counted at corporate level which are difficult to re-late uniquely to a specific mine project due to thepractice of consolidated reporting. Profit-basedroyalties may remain absent until a mine has re-couped all its investment. Instead, unit-based and advalorem taxes are levied at project level and im-posed at the mine gate. Unit-based and ad valorempayments help bridge the income gap for the hostgovernment and help to appease any public per-ception that the mine delays profit-sharing un-fairly—because unit-based payments start flowing tothe treasury as soon as production commences.

A profit-based tax rate that ensures a share inwindfall profits seems reasonable. For example, one

Fig. 31. Combined effect of ad valorem and profit-based re-

source rent taxation. (Graph source: Hogan and Goldsworthy

2010).


could consider geared royalties (Collier 2010) orprogressive royalty rate on profits, which for Ango-lan oil contracts is IRR-based an moves from a baserate of 25% profit share for IRR £ 15%, to 35% for15<IRR £ 25%, to 55% for 25<IRR £ 30%, to75% for 30<IRR £ 40% and to 85% for IRR>

40% (Nakhle 2008, 2010). A drawback of profit-based taxation is the considerable risk of disputesand litigation about deductibles. In practice, com-panies may have excessive room for deductionswhich minimize booking of profits in subsidiaries bytransfer pricing: importing mining machinery at in-flated cost prices and selling mineral exports belowmarket value. These situations may lead to incur-rence of costly legal fees that drain the treasury.Such disputes can only be avoided or at least mini-mized if the tax authority is empowered and issues aset of consistent and fully understood legislation onapplicable royalty rates. Governments seek tomaximize revenue from taxes and royalties andminimize cost of legal fees and political risk. Con-tinual consultation and dialog and information pro-vision to tax authorities should be honored andaccommodated by mining companies. If a miningcompany fails to comply, appropriate penaltiesshould be imposed and promptly collected upon riskof forfeiture of assets.

Fiscal Stability Agreements

When amining companymakes an investment ina country, it is possible in some jurisdictions to agreeto a level of fiscal stability with the government, such

that certain tax increases will not apply to the com-pany under the terms of the stability agreement(Daniel and Sunley 2010). For example, Argentinahas a statutory fiscal stability agreementwith a termof30 years. Chile also has a fiscal stability regime, whichsets down certain rights and benefits for non-Chileaninvestors, including taxes such as the specific miningtax rate and mining licenses. The Republic of theCongo permits a mining company to enter into a taxstability agreement in which the tax rates and tax baseare negotiated with the government and the specifictax regime must be ratified by the government to beenforceable. Indonesia has historically entered intotax stability agreements, but Indonesia�s system of taxstability contracts between the government and themining company ended in 2009. The Indonesiangovernment is seeking to re-negotiate its existingmining ‘‘Contracts of Work’’ to bring mining com-panies in line with the current tax regime. Despite theexistence of fiscal stability agreements, in Peru like-wise, the government enacted a special mining con-tribution applicable to companies with tax stabilityagreements. The Peruvian government requestedthat companies voluntarily enter into agreementswith the government to pay the special mining con-tribution. Accordingly, the existence of a tax stabilityagreement does not necessarily ensure that the gov-ernment will not try to re-negotiate the tax stabilityagreement should the country have a substantial dropin tax revenues or increase in government expendi-tures during a crisis situation or economic downturn.

Meanwhile, many governments have adopted‘‘ring fencing rules,’’ which provision that companiesin determining income subject to corporate income

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)

Royalty tax basis Rate (% unless noted otherwise)

(1) Unit-based royalty $0.19303 per pound nickel

(2) Ad valorem—NSR times percentage 3.40

(3) Ad valorem—metal contained in ore at mine mouth, valued at international ref-

erence price times percentage

2.75

(4) Ad valorem—metal contained in concentrate at the mill, valued at international

reference price times percentage

3.24

(5) Ad valorem—metal contained in smelter product, valued at international reference

price, times percentage

3.34

(6) Ad valorem—gross sales, less transportation, handling, and freight, times per-

centage

3.45

(7) Profit-based—percentage of gross sales, less operating costs, transportation, han-

dling, and freight

3.94

(8) Profit-based—percentage of gross sales, less capitalized costs, operating costs,

transportation, handling, and freight

4.91

(9) Ad valorem—sliding-scale percentages of NSR 11.7/2.67/4.17

426 Weijermars

tax will no longer be allowed to offset the lossesincurred with respect to one mining site against theprofits generated from another mining site. Forexample, Kazakhstan requires companies operatingseveral assets to maintain separate accounts andrecords for tax purposes with respect to each activity(PWC 2012). The subsurface contract miner is notpermitted to offset costs of one mining contractagainst income of another contract or activity. SinceJuly 2010, Tanzania also has a ‘‘ring fencing rule’’ inthat losses incurred in one mine cannot be used tooffset profits of another mine, notwithstanding thatboth mines are part of the same legal entity. Ring-fencing rules apply as well in Ghana.

In general, many historic mining contractshave low royalty rates, and countries are seeking toraise tax revenue. However, unit-based and advalorem royalties generally feature provisions forpayment relief in case of cash flow hardship due tocommodity price weakness. If employment creationis important and mineral grades are too low togenerate reasonable profits, then governmentsshould consider waiving even unit-based taxation infavor of marginal monetization of the naturalresource.

Fiscal Regime and Company Profits

Figure 32a, b shows an example of the cumu-lative cash flow model for a hypothetical coppermine for a certain royalty level that remains staticover the 22-year life cycle of the mine assuming astable global economy. The assumed 18% discountrate flattens cumulative cash flow, which in year 7–8of the mine life leaves no NPV growth. Prudentinvestors would close the mine when after tax cashflow turns negative, which occurs in year 8. Thesensitivity analysis to tax rates suggests that thegovernment benefits most from the highest royaltyrates (Fig. 33a, b). However, for the mining com-pany, the projects NPV and IRR erode rapidly withincreasing government take, to a point where itwould become unattractive for a company to remainengaged. The mine could close prematurely. If thatwere to happen, resource wealth becomes de factosub-economic (i.e., the reserves are impaired). Suchimpaired resources, of course, may turn economicagain when another mining company engages andtakes a final investment decision to develop the re-sources, but this remains uncertain until it actuallyhappens.

Case Study: Chilean Copper Mine Taxes

Revenues from copper mining projects for along time have been very mildly taxed in Chile, al-though the country has been responsible for nearly40% of global copper supply (Otto et al. 2006).Royalties were only introduced in 2006. Over theperiod 1990–2001, the Chilean treasury had receiveda little over $10 billion from its state mining com-pany Codelco, but only $1.6 billion from privatecompanies over the same period (Pizarro 2004). Thetaxes received compared to overall productionmeans 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 taxpayments by transfer pricing, fiscal evasion practicesand creative accounting solutions.

The development of Disputada de las Condesmine provides a striking case study for the apparentdivergence in interests between the state and theoperator. The Chilean copper industry resurged inthe early part of the 20th Century. Anaconda andKennecott, two U.S. registered companies ownedthe four major mines since WWII. The propertieswere nationalized in 1971, by consolidation intoCodelco. A real copper bonanza re-occurred in the1990s with many foreign operators opening mines inChile (Table 9). La Disputada, now operated byAnglo American, was one of the first to be picked upby foreign investors after Chile�s socialist govern-ment of Allende was overthrown in 1973 by Pino-chet, who liberalized the market economy (butnothing else)—once again.

Exxon bought Disputada in 1978 and operatedthe mine for 22 years before selling to Anglo Amer-ican in 2002 (Aguilera 2004). Exxon never paid anytaxes on its copper production by utilizing accountingspace to forward carry losses and by applying interestson expensive loans from its parent company via anunusually high debt-to-equity ratio of its Chileansubsidiary. Even at the time of themine�s sales, Exxonclaimed no capital gains tax would be due; Chileantaxation rules would not be applicable to itsmine sale.Exxon�s book value for La Disputada was only $500million, but theminewas sold for $1.3 billion toAngloAmerican, which implied $800 million capital gainswas realized by Exxon, that is before tax. Chilean lawstipulated 35% tax on capital gains was due frommining asset sales. The $280 million tax due to Chilewas 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 vehementlymaintained its prior agreement with the governmentwould dispense it from any capital gains taxationplight.

Finally, a sliding-scale revenue-based royalty(0–5%) was introduced by the Chilean governmentin 2006 (Hogan and Goldsworthy 2010), which hasalready lead to the accumulation of over $22 billion

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).

428 Weijermars

in its copper funded SWFs as per January 2014(Table 4 in main text).

APPENDIX 2: BRIEF OUTLINE OFPRINCIPAL AGREEMENTS FOR OILAND GAS RESOURCE DEVELOPMENT

This summary is based on data compiled byOswald Clint, Iain Pyle and Rob West at BernsteinResearch (Clint et al. 2013).

Royalty and Taxation Agreement (RTA)

The majority of OECD countries tax oil and gasproduction using a royalty and tax regime. Royaltiesare charged as a percentage of revenue earned fromproduction, and income taxes are then charged as apercentage of operating profit. Table 10 includes asimplified example of the government entitlementunder RTA. Under a royalty and tax regime, the taxrate is not sensitive to the oil price, making the netincome of operating companies more sensitive to the

oil price than under other tax regimes. This can be arelatively simple tax system: The income tax ratecharged will often be the country�s standard corpo-rate tax rate plus an additional resource tax, as is thecase in Norway. Brazil is another example of aroyalty and tax regime, but one that is more com-plex. Royalties are charged at 10%, and Braziliancorporate tax is charged at 34%. However, there isalso an additional Special Participation Tax (SPT)charged on the pre-salt fields of 40% prior to cor-porate tax, making the income tax charged on oiland gas production actually 61.4%. The SPT androyalties are reported under production cost, andjust the corporate tax is shown as income tax.Reporting of production taxes is inconsistent evenwith the FAS 69 disclosure (FASB 2010).

Production Sharing Agreement (PSA)

PSAs are generally used by non-OECD oil andgas-producing nations. A simplified PSA is de-scribed in Figure 34. When oil or gas is produced,the operating company can recover costs of

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

Company 2003 outputa First production Ownership

Codelco

Chuauicamata 601 Pre-1980 Government of Chile

El Teniente 339 Pre-1980 Government of Chile

Radomiro Tomic 306 1998 Government of Chile

Andina 236 Pre-1980 Government of Chile

Salvador 80 Pre-1980 Government of Chile

Output-Codelco 1,563

Other producers

Escondida 995 1990 BHP Billiton, RioTintopIc, Mitsubishi, IFC

Collahuasi 395 1998 Anglo American, Noranda

Los Pelambres 338 1999 Mitsui, Nippon Mg Hold Antofagasta

Disputada 278 Pre-1980 Anglo American

El Abra 227 1996 Phelps Dodge, Codelco

Candelaria 213 1994 Phelps Dodge

Zaldivar 151 1995 Placer Dome

Mantos Blancos 147 Pre-1980 Anglo American

Cerro Colorado 132 1994 BHP Billiton Gr

Enami 122 Pre-1980 Government of Chile

El Tesoro 92 2001 Antofagasta, Eguatorial

Quebrada Blanca 80 1994 Aur Resources Inc.

Lomas Bayas 60 1998 Noranda

Michilla 53 1994 Antofagasta

Others 61

Output, other 3,342

Total output 4,904

aOutput is in thousands of tonnes of contained copper

Source: Copper Commission of Chile, as detailed in Otto et al. (2006)


production (this portion of production is termedCost Oil), before any additional volumes (ProfitOil) is split between the government and the con-tractor. The ratio of the Profit Oil split is deter-mined by a sliding scale, which is based oncomplicated formulas generally established by theIRR for the project to date. Table 10 (middle col-umn) includes an example of government entitle-ments under PSA. The tax take also variessignificantly through the life of the project. In theearly stages, while the operator is still recoveringCAPEX, the IRR up to that point is low andtherefore the government�s share of Profit Oil islow; in later years, CAPEX spend slows and theIRR likely moves above a threshold, meaning thegovernment share of Profit Oil increases, often to aproportion of around 80%. PSA tax regimes tend tobe sensitive to the oil price. A high oil price meansthat operators earn costs back quickly and havehigher returns, resulting in the government takingan increased share of production.

Service Contract Agreement (SCA)

The third type of tax regime is a service contractagreement, which is much less common than taxrates or PSAs. The integrateds have some exposuredue to SCAs being used in the UAE and Iraq forcontracts awarded after the second Gulf War. Underthe service agreements, the operators receive a fixedfee for each barrel of oil produced above a fixedlevel. 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 remainsinsensitive to any oil price windfall or loss. Table 10includes an example of the government FEP underSCAs.

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

The below treatise on the evolution of U.S.federal leasing policies is largely based on sourcesand details summarized in a popular essay byFreudenberg and Gramling (2011) and Krueger andSinger (1979). Leasing of land from private mineralright owners in the U.S. is concisely covered byTinkler (1992) and McFarland (2006). Terms usedfor U.S. oil and gas taxation are defined a by theU.S. Internal Revenue Service (IRS 2013).

Initially, the U.S. federal Mining Law of 1872commonly would grant a claim patent in exchangefor about $5/acre. In 1913, U.S. Congress grantedmining and oil companies a depletion allowance,amounting to a tax deduction of 5% of the grossvalue of production to enable investment in thedevelopment of new mines, essentially granting aHotelling rent. The War Revenues Act of 1918 re-vised the 5% tax break based on gross productionwith a provision to deduct either the cost or the fairmarket value of a new discovery, which couldamount to 28–31% of the companies� gross income.In 1926, the War Revenues Act was changed to27.5% of gross income, which basically lasted untilthe 1970s, when U.S. tax policy effectively allowedoil companies to defer taxes on roughly a quarter ofthe production income.

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

RTA PSA SCA

Equity production 9 price 100 100 100

Government share 0% 30% 100%

Entitlement production 9 price 100 70 0

Royalty rate 10% 0% 0%

Royalty 10 0 0

Operating costs 30 21 0

DD&A 15 11 0

Operating profit 45 39 0

Operating margin 45% 55% n.a.

Income tax rate 60% 53% 0%

Income tax 27 21 0

Service fee 0 0 2

Net income 18 18 2

Government entitlement (FEP) 67% 74% 98%

Source: Bernstein Research

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Leasing of federally owned land was first madepossible by the Mineral Policy Act of 1920, whichreplaced the previous Mining Law of 1872. TheMineral Policy Act granted 10-year leases for theright to extract publicly owned deposits of oil andminerals. The general principle was that the leaseswould be awarded based on a competitive biddingprocess. However, there were irregularities of whichTeapot Dome Scandal was one of the most notori-ous. It involved Secretary of the Interior, AlbertFall, who was convicted and jailed for acceptingbribes for the awarding of Naval PetroleumReserves without competitive bids between 1922and 1923, including Teapot Dome, Wyoming (Davis2001; McCartney 2008).

California was the first state to adopt a legalframework for the leasing of offshore tracts, i.e., inthe Santa Barbara Channel, in the early 1900s. In1929, the California State Mineral Leasing Act wasrepealed and offshore leasing curtailed. That yearPresident Hoover also withdrew federal lands fromleasing in an attempt to counter the risk of over-production of oil after major discoveries in Texas,Oklahoma and California. In 1931, state laws werepassed in both Texas and Oklahoma to preventexceeding production quotas, but prices continued

to fall, which lead to the imposition of import tariffson foreign oil. In 1927, the first oil cartel meetingtook place in Scotland where Shell, BP (then Anglo-Persian) and Exxon (then Standard Oil) worked outthe Pact of Achnacarry (Yergin 1991). Price fixingby the international petroleum cartel was uncoveredby the U.S. Federal Trade Commission in a 1952report (FTC 1952), but was continuing at least untilthe oil embargo of 1973–1974.

Although states that experimented with off-shore leases (Louisiana, Texas, Florida and Cali-fornia) had been assuming that they were the legalowners of offshore tracts, the federal Governmentdid not agree. Assertion of Federal ownership wasfirst attempted in a resolution proposal to the U.S.Senate in 1937 (Harold Ickes), but the House ofRepresentatives took no action. The State Land Actof 1938 gave California legal control over offshoreleasing and limited offshore development resumed.Louisiana offered its first ever offshore lease notuntil 1945, granting a 194,000 acre tract to a singlebidder company (Magnolia Petroleum Co.) that la-ter became part of Exxon Mobil. Lousiana CaddoLake field (Louisiana) was developed in the 1910susing shallow platforms, which were subsequentlymoved to the 12-feet deep Lake Maricaibo

Fig. 34. Simplified project economics comparing operator profits and FEP payments to government according to a generic

PSA schedule. Source: Bernstein Research.


(Venezuela) with a first well drilled in 1924. Pipelinecorridors in the Louisiana marshes were alreadycommon where large-mounted draglines carved anetwork of canals in the wetlands and cleared theway for the Giliasso drilling barge around 1932.

In 1945, Harold Ickes persuaded PresidentTruman to issue Executive Order 9633 (FR12304(1945);59 Stat. 885) and asserted federal ownershipof offshore oil lands. A federal suit was initiatedagainst California in the U.S. Supreme Court in whatbecame known as ‘‘The Tidelands Controversy’’(Engler 1961;Cicin-Sain andKnecht 1987). Texas andLouisiana continued with leasing and legal battleswith the federal government dragged on for yearsuntil the U.S. Supreme Court established the legalrights of the federal government over all offshorelands in a series of decisions between 1947 and 1950.

In 1953, U.S. Congress passed the SubmergedLands Act, granting states title to seaboard within 3miles of the shoreline, but asserting federal owner-ship of all resources under federal offshore waters.Texas and West Florida received a state seaboard of3 marine league (approximately 10.4 miles) in theirruling. The second law adopted was the OuterContinental Shelf Act (OCSA) which offered leasesthrough a competitive bidding process. Californiaand Florida and Alaska had successfully opposedfederal lease auctions in Washington DC DistrictCourt since the mid 1970s.

In 1978, the Outer Continental Shelf Land ActAmendment (OCSLAA) stated purpose was toopen the decision-making process to a wider audi-ence and avoid collusion between a small group ofbidders and top-officials of the Department of theInterior.

In 1983, the area-wide sales were introduced byJames Watt of the U.S. Mineral Management Ser-vice (MMS). Offshore leases typically cover a 3 milesquare block which contains 5,670 acres. Tradition-ally, offshore leases required that federal govern-ment receives the bonus bids, plus one sixth of thetotal value of offshore resources extracted(16.666%). When area-wide sales started in 1983,some leases in greater water depths were offeredwith a royalty discount, demanding only one-eighthof the gross resource value produced (12.5%) tostimulate deep-water E&P. Before 1983, the averageacre dollar was $2,224. The area-wide leases soldbetween 1983 and 2008 averaged just $263/acre.

In 1995, U.S. congress passed the Outer Conti-nental Shelf Deepwater Royalty Relief Act(DWRRA, 1995). This is a royalty waiver program

aimed at stimulating development of hydrocarbonsin the deep-water Gulf of Mexico. Royalties weresuspended for 5 years in a tiered system that allowedroyalty-free production in deep-water areas of theGOM, defined as water depths below 200 meters, asfollows:

� 200–400 m: 98.5 bcf gas and 17.5 MMbbls oilroyalty free

� 400–800 m: 295.6 bcf gas and 52.5 MMbbls oilroyalty free

� >800 m: 492.6 bcf gas and 87.5 MMbbls oilroyalty free.

The original terms and conditions of theDWRRA expired in November 2000, and since thattime, the MMS assigns a lease-specific volume ofroyalty suspension based on how the determinedsuspension amount supports field developmenteconomics. According to the U.S. GovernmentAccountability Office, the waiver reduced the taxburden of the companies by $50 billion over the lifeof the leases (GAO 2007). The fiscal take in the Gulfof Mexico was estimated to amount to 45% based onClint et al. (2013) and Hendricks et al. (1987) esti-mated a fiscal take of 77% leaving only 23% forcompany profit, but incorrectly assumed a leasebonus as a cost rather than a tax deductable. Off-shore lease actions in the U.S. between 1954 and1990 have raised $282 billion, and the royalty to thegovernment at 1/6 (16.666%) of revenue amountedto $202 billion (Porter 1995; Cramton 2010).

The effect of fiscal stimuli on the developmentof new productivity becomes apparent in a compi-lation of the annual oil and gas production in theU.S. Gulf of Mexico plotted against tax measurestaken (Fig. 35). Particularly, field development inultra-deep water was stimulated by the 1995 royaltywaiver program. The lifting of the drilling ban forouter portions of the continental shelf by presidentBush Jr. before he left office in 2008 lead to anotherbrief revival of drilling activity.

Case Study: Kazakhstan Production SharingAgreements

The Caspian Sea region is an emerging oil andgas play, where the interests of oil and gas majorsand sovereign resource holders meet and strugglefor mutual profit optimization. Some U.S. energyfirms and other private foreign investors have

432 Weijermars

become discouraged in recent years by harsher Ka-zakh government terms (Nichol 2013). Foreigninvestors report that local government officials reg-ularly pressure them to provide social investments inorder 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), whichextracts oil and gas from the Karachaganak fields innorthwest Kazakhstan, was faced with an effort bythe Kazakh government to obtain 10% of the sharesof the consortium. Facing resistance, the govern-ment imposed hundreds of millions of dollars in tax,environmental, and labor fines and oil export dutiesagainst KPO. Both the government and KPO ap-pealed to international arbitration (Nichol 2013). InDecember 2011, KPO agreed to transfer 10% of itsshares to the Kazakh government, basically gratis,and in exchange the government mostly lifted thefines and duties. In July 2013, Kazakhstan exercisedits right to influence the disposition of subsoil re-sources by directing the transfer of the UnitedStates� ConocoPhillips 8.4% stake in the Kashaganoilfield to the China National Petroleum Corpora-tion (Nichol 2013). ConocoPhillips had planned tosell the stake to India�s Oil and Natural Gas Cor-poration. Other members of the North CaspianOperating Consortium developing the oil field cur-rently include Italy�s Eni energy firm, the Anglo-Dutch Shell, the United States� ExxonMobil, Fran-ce�s Total and Kazakhstan�s KazMunaiGaz (all witha 16.81% stake) as well as Japan�s Inpex (7.56%).Rising concerns over the Kazakh government�spolicies raised questions among the investor com-munity backing the foreign consortium members

about the timeline and feasibility of their efforts as asource of rising revenues from the oil field.

APPENDIX 3: GOVERNANCE ISSUESRELATED TO TRANSPARENCY ANDACCOUNTABILITY OF CORPORATEPROFITS AND FISCAL ENTITLEMENTPAYMENTS IN NATURAL RESOURCEEXTRACTION ACTIVITIES

Transparency About Concession Agreements

Oil companies generated from natural resourceexploitation corporate profits based on projects withprofitable IRR.Afiscal entitlement payment (FEP) isdue to governments with the intention to benefit thenational treasury. Corporate profits and FEPs ofmajor oil and gas projects can amount to billions ofdollars per year. Governments received FEPs asspecified in concession and licensing agreements (seeAppendix 2). Precisely how much money is paid inindividual projects and towhom remains often hiddenin consolidated profit-loss accounts of companies andthe same rules for the mineral resource treasuries ofmany nations (both OECD and non-OECD).

One could argue that information pertinent to anation�s natural resource wealth sharing should bepublicly available because it is in the interest of thepeople whose legal representatives must responsiblymanage the resources of a given country. Indepen-dent research is handicapped by the fact that manyconcession and licensing agreements are confiden-tial. Nearly all companies consider their contracts asproprietary information with competitive value. Themajority of governments closely guard their agree-ments for individual fields in the same way, so thatdetails often remain shrouded in obscurity. In fairtrade, it remains important to know precisely hownatural resource endowments are exchanged intolong-term wealth for a country and its citizens.

Accountability Standards and Rating of Oil Funds

The Resource Governance Index (RGI) out-lined in the main text subsection ‘‘Reputation of theMining Industry’’ is not only applied to countries butalso to a pool of natural resource funds (SWFs) andto a number of national oil companies (100% state-owned or partially state-owned after partial privati-zation). Table 11 lists the RGI scores for SWFs

Fig. 35. Annual production output from the U.S. Gulf of Mex-

ico. Adapted from Bernstein Research.


related to petroleum revenues. Comparison toTable 3 in the main text reveals that some of thelargest SWFs have RGI scores less than 70 andtherefore are governed in a manner that is onlypartially fulfilling RGI standards (RGI 70-51), out-right weak (RGI 50-41) or failing (RGI below 40).The RGI assessment by the Revenue Watch Insti-tute can be compared with the Linaburg–MaduellTransparency Index (LMTI), developed by CarlLinaburg and Michael Maduell at the SovereignWealth Fund Institute. The LMTI is another methodof rating transparency pertaining to government-owned investment vehicles. The index is based on 10essential principles that depict SWF transparency tothe public. The minimum rating a fund can receive isa 1 and maximum a 10. Low scores apply when therehave been concerns of unethical agendas and

‘‘opaque’’ or non-transparent governance of funds.Transparency ratings may change as funds releaseadditional information.

Scores of LMTI are included in Table 11. Thisalso reveals consistencies in SWF governance ratings(Norway, Russia, Iran, East Timor), but also somegreat disparities (Kuwait, Qatar, Azerbaijan, Mex-ico), with reasonable close ratings for a number ofcountries (Kazakhstan, Canada, Algeria, Nigeria,Trinidad & Tobago). Clearly, the rating of SWFgovernance is in its infancy.

Rating of National Oil Companies

National oil companies are a main source ofGDP and fund a major portion of government

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

Country Name of SWF RGI 1/100 LMTI 1/10

Norway Government Pension Fund-Global 100 10

Trinidad & Tobago Heritage and Stabilization Fund 98 8

East Timor Timor-Leste Petroleum Fund 83 8

Mexico Oil Revenue Stabilization Fund of Mexico 79 4

Canada-Alberta Alberta�s Heritage Fund 73 9

Kazakhstan Kazakhstan National Fund 67 8

Iran National Development Fund Iran 50 5

Russia National Welfare Fund 46 5

Russia Reserve Fund 46 5

Azerbaijan State Oil Fund Azerbaijan 44 10

Angola Fundo Soberano de Angola 25 n/a

Saudi Arabia Public Investment Fund 19 4

Nigeria Nigerian Sovereign Investment Authority 17 4

Kuwait Kuwait Investment Authority 15 6

Algeria Revenue Regulation Fund 6 1

Qatar Qatar Investment Authority 2 5

Libya Libyan Investment Authority 0 1

UAE-Abu Dhabi Mubadala Development Company n/a 10

US-Alaska Alaska Permanent Fund n/a 10

UAE-Abu Dhabi International Petroleum Investment Company n/a 9

US-Texas Texas Permanent School Fund n/a 9

US-New Mexico New Mexico State Investment Council n/a 9

US-Alabama Alabama Trust Fund n/a 9

UAE-Abu Dhabi Abu Dhabi Investment Authority n/a 5

Saudi Arabia SAMA Foreign Holdings n/a 4

UAE-Dubai Investment Corporation of Dubai n/a 4

Oman State General Reserve Fund n/a 4

Oman Oman Investment Fund n/a 4

UAE-Ras Al Khaimah RAK Investment Authority n/a 3

UAE-Federal Emirates Investment Authority n/a 3

Brunei Brunei Investment Authority n/a 1

Iraq Development for Iraq n/a n/a

Kazakhstan National Investment Corporation n/a n/a

US-Louisiana Louisiana Education Quality Trust Fund n/a n/a

US-North Dakota North Dakota Legacy Fund n/a n/a

US-Texas Permanent University Fund n/a n/a

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budgets in many nations. For example, more thantwo-thirds of total government revenue in Azerbai-jan, Iraq and Yemen are funded by the profits oftheir respective national oil companies (RWI 2013).Table 12 lists the RGI scores for the governanceperformance of major national oil companies (someof which have been partly privatized, e.g., Statoiland Petrobras). The accountability of national oilcompanies that Revenue Watch Institute measuresis the company�s compliance with internationalaccounting standards, disclosure of data and auditson production and revenues, publishing of reportsthat are transparent about risks of extra-budgetaryspending and disclosure of company contribution tothe government budget. It is worth noting that theworld�s largest oil producer, Saudi Aramco with anoutstanding technical record, scores a meager RGIof 42 (Table 12).

National oil companies that are 100% state-owned and derive a major part of their revenuesfrom domestic upstream activities do not experience

the polarized viewpoints that govern negotiationsbetween foreign companies and governments thatmanage national resource endowments they want todevelop and produce. However, state oil companiesare essentially regulated companies, which mustfiercely negotiate with their regulatory agency tomake sure that enough earnings are retained for newcapital intensive development projects. For suchnegotiations, it is useful to avail better tools forestablishing the fair value in extraction projects. Thiswill help finding a right balance between govern-ment FEPs and profits retained for sustained oper-ations by the national oil company.

Transparency of International Oil Companies

International oil companies have annual reve-nue streams surpassing the GDP of many countriesin which they hold assets. For example, Shell 2012revenues of $467 billion exceed the combined 2012GDP of Nigeria, Angola and Gabon (Fig. 36a). Arecent report by Africa Progress Panel (Geneva;APR 2013) has highlighted how collusion of theextractive industry and weak governments can de-prive nations from receiving fair value for its ex-tracted natural resources. Shell was not implied inthis study, but the mining industry was shown to becomplicit. A detailed analysis of five major mineralextraction concessions in Congo granted in theperiod (2010–2012) lead to the conclusion that thesewere underpriced (APR 2013), and resulted in acompounded loss for the Treasury of $1.36 billion.The lost sum would have been sufficient to covertwice the total health and education budget ofCongo (Fig. 36b). Clearly, governance of naturalresource wealth is still weak in many nations, andthere is ample room for improvement (RWI 2013).

Petroleum laws being developed or reformed,particularly in many African countries, will have animportant bearing on citizens and civil societygroups to secure access to natural wealth-sharinginformation. A recent survey of petroleum laws offive countries (Ethiopia, Ghana, Liberia, Ugandaand Zimbabwe; Veit and Excell 2013) reveals weakprovisions for the enforcement of the right to accessinformation, and appeal against refusal. Some lawsoblige the executive branch of government to reportto the legislature, but the detail of the information tobe provided remains a matter of interpretation (Veitand Excell 2013): ‘‘…while all laws require licenseesto provide the government with information, most

Table 12. RGI Scores National Oil Companies—Revenue Watch

Institute—(RWI 2013)

Company Country RGI

Statoil Norway 99

Pemex Mexico 98

Petrobras Brazil 92

ONGC India 92

Rosneft Russia 92

Ecopetrol Colombia 88

PDVSA Venezuela 87

KazMunaiGaz Kazakhstan 87

Pertamina Indonesia 86

CNPC China 82

Sonangol Angola 70

Petromin Papua New Guinea 69

SOCAR Azerbaijan 67

Petrotrin Trinidad and Tobago 66

KPC Kuwait 63

Petroecuador Ecuador 62

Petronas Malaysia 61

YPFB Bolivia 53

Sonatrach Algeria 49

NNPC Nigeria 47

YOGC Yemen 44

Aramco Saudi Arabia 41

Petrovietnam Vietnam 40

Qatar Petroleum Qatar 37

Nile Petroleum South Sudan 31

ENH Mozambique 36

Lybian National Oil Corporation Libya 19

NIOC Iran 15

BAPCI Bahrain 14

Turkmengas Turkmenistan 0


are silent on how the information should be sharedand what the government should do with it.’’ Forexample (Veit and Excell 2013), ‘‘Uganda�s Petro-leum Bill requires licensees to keep records of a widerange of information on the quantity and quality ofcrude oil reserves, discovery, and drilling opera-tions,…Confidentiality clauses are unclear aboutwho can access confidential information, how longinformation can be deemed confidential and howclaims of confidentiality can be challenged in thepublic interest. By not clearly delineating what isconsidered confidential, legislation leaves governmentofficials with considerable discretionary authority.Most laws incorporate harsh sanctions against therelease of confidential information. Coupled with theambiguity surrounding what is confidential, this cre-ates a perverse incentive for officials to err on the sideof withholding information.’’

It should also be highlighted that most inter-national oil companies are struggling to face therealities of being truly transparent about their rev-enues and profits on a project-by-project basis. TheAmerican Petroleum Institute is lobbying on behalfof its members (Chevron, Exxon, Shell, BP and allother major oil and gas companies, independentsand service companies active in the U.S.) to seekannulment 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). Fortactical reasons companies would like to continue tobe less transparent about the profitability ofindividual projects and prefer to stick to the currentconsolidated reporting of profits per country orregion.

Renegotiation of Agreements

Governments who provide tax concessions inorder to attract investments from natural resourcesextraction companies must be cautious not to offerexcessive discounts. Renegotiation of contractsafterward is not always feasible. However, the gov-ernment of Liberia [with and RGI of 62 (RWI 2013)and listed as EITI compliant (EITI 2013) but with apoor transparency of government budgets (OpenBudget Index of 43 on a scale of 100; IBP 2012)]reviewed 105 concession agreements signed between2003 and 2006. The reviews screened for fair value ofthe FEP stipulated in the concession agreements andconcluded that 36 agreements should be canceledand 14 renegotiated (APR 2013). Renegotiation wascarried out with international assistance and resultedin major changes to a significant number of conces-sion agreements (Gajigo et al. 2012). Cases like theseprovide evidence for the need to develop better toolsfor establishing fair value in extraction projects inorder to find a proper balance between governmentFEPs and profits for the extractive company.

LIST OF ACRONYMS

APR Africa Progress Panel ReportBbl Barrelbcf Billion Cubic FeetBG British Gasboe Barrel of Oil EquivalentBP British Petroleum

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 en-

ough to cover twice the country�s health and education bills.

Source: APR (2013).

436 Weijermars

C-ENRD Center for Equitable NaturalResource Development

COW Contract of work system (Indonesia)CRIRSCO Committee for Mineral Reserves

International Reporting StandardsDD&A Depreciation, Depletion and

AmortizationDL DeloitteDOI Department of the Interior (U.S.)DRC Democratic Republic CongoEC European CommissionE&P Exploration and DevelopmentEIA Energy information AdministrationEIB European Investment BankEITI Extractive Industries Transparency

InitiativeENRC Eurasian Natural Resources

CorporationEU European UnionEUR Estimated Ultimate RecoveryFASB Federal Accounting Standards BoardFEP Fiscal Entitlement PaymentGAO Government Accountability Office

(US)GDP Gross Domestic ProductGEM Global Economic Model

(WoodMackenzie)GOM Gulf of MexicoGT Grant ThorntonIMF International Monetary FundIRR Internal Rate of ReturnJORC Australasian Joint Ore Reserves

CommitteeKPI Key Performance IndicatorKPO Karachaganak Petroleum OperatingLMTI Linaburg–Maduell Transparency

IndexLNG Liquefied Natural GasMCM Mopani Copper Mine (Zambia)MMbbls Million BarrelsMMS Mineral Management Service (US)MPRDA Mineral and Petroleum Resources

Development Act (South Africa)NAM Nederlandse Aardolie Maatschappij

(Netherlands)NPV Net Present ValueNSR Net Smelter ReturnOCSA Outer Continental Shelf ActOCSLAA Outer Continental Shelf Land Act

Amendment

OECD Organization of EconomicCooperation Development

ONGC Oil and Natural Gas Corporation(India)

OPEX Operating Capital ExpenditurePRMS Resources Management SystemPSA Production Sharing AgreementPWC Pricewaterhouse CoopersRAND Research and Development

Corporation (US)RGI Resource Governance IndexROCE Return on capital EmployedROI Return on InvestmentRTA Royalty and Taxation AgreementRWI Revenue Watch InstituteSCA Service Contract AgreementSEC Securities and Exchange Commission

(US)SME Society for Mining, Metallurgy, and

ExplorationSG&A Selling, General and Administrative

ExpenseSPT Special Participation TaxSWF Sovereign Wealth FundUAE United Arab EmiratesUK United KingdomUN United NationsUS United StatesWACC Weighted Average Cost of Capital

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