## 1. EI Revenue Potential: Selected African Countries ## Source details **Canonical URL:** [1. EI Revenue Potential: Selected African Countries](https://www.imf.org/-/media/websites/imf/imported-full-text-pdf/external/np/pp/eng/2012/_081512.pdf) ## Other formats - [Markdown version](/-/media/websites/imf/imported-full-text-pdf/external/np/pp/eng/2012/_081512.pdf.md) - [Structured JSON version](/-/media/websites/imf/imported-full-text-pdf/external/np/pp/eng/2012/_081512.pdf.json) --- ### Executive summary — key findings and benchmarks - EI (oil, gas, and mining) often account for over half of government revenue in petroleum-rich countries, and for over 20 percent in mining countries. - Dependence on EI revenues in resource-rich countries is now about one-third of the Fund’s membership. - Mining: observed government retention commonly one-third or more; simulations suggest government shares of 40–60 percent (simulations may not capture all revenue erosion). - Petroleum: simulations suggest government share around 65–85 percent. - Fiscal regimes raising less than these benchmark averages may be cause for concern. - Preferred regime structure for many developing countries: royalty + rent-targeted tax + standard corporate income tax: - ensures some revenue at start of production; - government revenue rises with rents (higher prices or lower costs); - can enhance stability and credibility; - balances administrative challenges across instruments. - Effective administration, coherent responsibilities, and transparent rules/contracts are critical; poorly designed international tax arrangements can seriously undermine revenue potential. ### Selected country/project revenue potentials (Table 1) - Notes: estimates show order of magnitude; projections sensitive to prices, phasing, production and capital costs; data represent annual revenue at peak production where noted. - Ghana, Jubilee (Phase 1 only) - Investment US$bn: $3.15bn - Average annual revenue potential (US$bn, constant 2011 dollars; percent 2011 GDP): $0.85bn; 2.3 - Lifespan: 21 years - Guinea, Simandou, and others - Investment US$bn: $4bn (mining) + $6bn infrastructure - Average annual revenue potential: $1.6bn; 30.7 - Lifespan: 21 years - Liberia - Investment US$bn: $4.5bn - Average annual revenue potential: $1.7bn; 147.8 - Lifespan: 20–30 years (iron ore); potential 20+ for petroleum (no proven project yet) - Mozambique, Rovuma (gas) Tete (coal) - Investment US$bn: $20-30bn - Average annual revenue potential: $3.5bn; 27.3 - Lifespan: 30–50 years - Sierra Leone, various - Investment US$bn: $4.6bn - Average annual revenue potential: $0.4bn; 18.2 - Lifespan: 15 years - Tanzania - Investment US$bn: $20-30bn - Average annual revenue potential: $3.5bn; 15.0 - Lifespan: 10–20 years (gold remaining in existing mines); 20–30 (gas and nickel) - Source: IMF staff estimates. ### Revenue potential from oil — key calculations and examples - Exploration and development costs estimate for East Africa: $6–14 per barrel. - With oil at $80 per barrel and governments securing 50 percent of price–cost surplus, increasing production by 1 million barrels per day increases government revenue in sub-Saharan Africa by about $12 billion annually, or 1 percent of the 2011 GDP of sub-Saharan Africa. - Angola increased production by 1 million barrels per day over 2001–11 while more than doubling proven reserves. - Sub-Saharan Africa increased proven reserves by 50 percent over 2001–11 (to 68 billion barrels). - Iron ore reserves in sub-Saharan Africa could provide an estimated 120 years of total world supply (out of about 500 available globally); if developed and apportioned over 500 years, annual revenue addition would be about 0.7 percent of region’s 2011 GDP. ### Central fiscal issue — government share of rents and objectives - Rents defined as excess of revenues over all costs including discovery and development and normal return to capital. - Theoretical maximum tax on rents: up to 100 percent (practically infeasible). - Primary fiscal objective: maximize present value of net government revenues — best served by taxes explicitly targeted on rents. - Practical constraints: - asymmetric information; - difficulty observing revenues and costs; - need to provide adequate investor incentives (exploration, development). - Timing matters: governments with limited credit or political pressure may favor early revenue (royalties); willingness to defer revenue (lower royalties, accelerated depreciation, reliance on rent taxes) can reduce investor required returns. - Progressivity: extent revenue rises with commodity price increases or cost decreases; trade-offs between investor incentives and government revenue progressivity. ### Instruments, variants, and representative numeric examples - Major instruments: bonuses (signature/discovery/production), royalties (gross, ad-valorem, progressive), Corporate Income Tax (CIT), variable income tax (VIT), resource rent taxes (Brown tax/R-based cash flow, ACE/ACC), production sharing contracts (PSC) with DROP, cumulative production, R-Factor, ROR variants, and state participation (free, carried, paid equity). - Box 2 summary (two leading rent tax forms): - Brown Tax (R-based cash flow tax): immediate expensing, refund/carry forward of losses with uplift; used in Australia (mining/petroleum) and Angola (PSC mechanism); usually ring-fenced. - ACE/ACC: deduction for imputed return on book equity (ACE) or notional interest on capital (ACC); Norway’s petroleum tax approximates ACC. - Representative numeric/mechanism examples: - Deep water well cost example: over US$100 million. - Chance of success in a new basin example: 1 in 20. - CIF iron ore price example: $107 per ton; overall costs example: $70 per ton; government share example: 40 percent of surplus. - Suggested AETR target ranges from simulations: Mining: 40–60 percent; Petroleum: 65–85 percent. ### Country-level simulations — exploration, EMV, and investor incentives - Simple regional assumption: discovering and developing a single additional oil field in each of at least 18 countries with petroleum potential would add nearly 2 percent of collective GDP to revenues in peak production years. - EMV framework (Appendix Box 1): - EMV = p × NPVProject × (1-TaxRate) – (1-p) × NPCExplore × (1-TaxRefund) - Typical p (probability of commercial discovery): 10–20 percent. - Example: with p = 15 percent, regimes with fixed large upfront charges can be unviable — $1.925bn signature bonus is unviable at 15 percent success; maximum bonus consistent with positive EMV at 15 percent success: $230mm. - Simulation findings (Smith (2012) and FARI exercises): - Tax regime with government take ≈ 50 percent of quasi-rents on success reduces acceptable number of exploratory failures by 15–25 percent (negative impact on exploration). - A 20 percent royalty or 40 percent minimum profit oil share reduces initial investment by ~20 percent and extraction rate by ~1 percentage point per year; delays enhanced recovery by 1–2 years. - Revenue-based mechanisms (royalties, signature bonuses) raise expected AETR and investor downside risk under price uncertainty; signature bonus especially punitive. - Resource rent taxes can create negative marginal effective tax rates (implicit subsidy) if uplift rates exceed firms’ cost of capital, incentivizing “gold plating.” ### FARI model outputs, AETR and METR diagnostics - FARI model: calculates Average Effective Tax Rate (AETR) — government’s share of pre-tax NPV (measured at government discount rate) — and various indicators (METR, progressivity, investor IRR, payback). - FARI simulation examples (Offshore 290 MMbl base case: Oil price $90 per barrel; Costs per barrel $23.0; IRR pre-tax: 39%; Discount Rate: 10.0%): - All regimes can be calibrated to same base-case AETR but respond differently to price/cost changes. - Royalty regimes respond little to price/cost variation and distort project selection. - Indicative AETR ranges from methods: - Petroleum: around 65–85 percent (simulation and accounting evidence). - Mining: around 40–60 percent (simulations) and illustrative IETR evidence around 35–45 percent. ### Administration, institutional design, and transparency - Administrative realities: - EI regimes often complex and fragmented, impairing effective tax administration despite measurable outputs and international prices. - Common problems: fragmented responsibilities across ministries/NEICs/tax administrations; weak routine processing; inefficient royalty administration (no annual reconciliation). - Royalties are not always easier to administer (valuation, netback issues); rent/profit taxes are not necessarily harder (e.g., R-based cash flow tax avoids depreciation/interest issues). - Institutional recommendations: - Separate fiscal roles from regulatory/commercial roles; place fiscal roles in tax department where feasible. - Share physical audit information between EI ministry and tax administration. - Adopt simple, clear legislation with minimum number of taxes. - Organize administration by functions (registration, audit, compliance) and use risk-based audit allocation. - FAD technical assistance: around 85 TA missions in 37 countries (FY2006–12); 2012: 31 missions; growing HQ-led TA planned. - Transparency: - Opacity arises from confidential contracts, fragmented filings, revenues paid in kind, and lack of single accounting responsibility. - Initiatives: EITI (company payments and government receipts published, audited, reconciled); Section 1504 (Dodd-Frank) and EU proposals increase disclosure; IMF’s Guide on Resource Revenue Transparency (2007). ### International tax issues and revenue protection - Transfer taxation on sales of exploration/project interests can be large (example: about $400 million in one Ugandan case). - Tax treaties can erode tax base (reducing/eliminating WHTs; “treaty shopping”). - Transfer pricing risk elevated in upstream activities; mitigating features include observable outputs and joint ventures. - Good practice: transparent transfer pricing rules, industry benchmarks, taxpayer onus to demonstrate arm’s length pricing, robust data collection for risk-based audits. - Auctions and granting rights: - Auction design matters; bid variables may include bonuses or fiscal parameters; auctions need sufficient qualified bidder participation and anti-collusion measures. - Separating exploration from extraction rights can be beneficial where feasible and where governments can credibly acquire/hold exploration data. ### Key quantitative diagnostics and thresholds preserved from source - Exploration success probabilities: 10–20 percent (typical); 15 percent used in illustrative EMV. - Deep water well cost example: over US$100 million. - Example uplift and thresholds: - Norway-style uplift: 30 percent uplift on capital over 4 years (example). - Australia-style PRRT uplift: bond rate + 15 percent (exploration) and bond rate + 5 percent (other expenditure) in one formulation. - FARI-determined suggested AETR ranges: - Mining: 40–60 percent. - Petroleum: 65–85 percent. - IETR illustrative results: - Mining IETR (Appendix Table 9): 2005=46.3%; 2006=37.2%; 2007=35.7%; 2008=36.9%; 2009=90.1%; 2010=40.2%. - Petroleum IETR (Appendix Table 10, J/I): 2005=44%; 2006=63%; 2007=65%; 2008=59%; 2009=70%; 2010=69%. - Signature bonus example: $1.925 Bn (unviable at 15% success); maximum bonus consistent with positive EMV at 15% success: $230mm. - Project cost profile (Offshore 290 MMbl): - Total project costs: $6,592mm - Per barrel total: $23.0 - Exploration: $330mm (1.1 $/Bl); Development costs: $2,500mm (8.7 $/Bl); Sustaining capital: $1,125mm (3.9 $/Bl); Operating costs: $2,387mm (8.3 $/Bl); Decommissioning: $250mm (0.9 $/Bl). ### Policy recommendations and practical guidance (preserving source judgments and terminology) - Aim fiscal regimes at explicitly taxing rents while preserving adequate investor incentives to explore and develop. - For LICs and many developing countries, a combined regime of: - modest ad valorem royalty (early revenue), - CIT (normal return taxed as in other sectors), - resource rent tax (captures surplus/rents), offers practical appeal. - When designing rent taxes and uplift: - Use lower uplift rates and consider time-limiting them (staff advice). - Avoid uplift rates materially above firms’ cost of capital to reduce gold plating and negative marginal effective tax rates. - Prefer single-tier ROR schemes to multi-tier versions to limit gold-plating incentives. - Address exploration risk explicitly: - Refund failed exploration costs (where government can credibly do so) or permit effective loss offsets to maintain exploration incentives. - Improve government geological information to reduce exploration risk and enable higher government shares on success. - Improve administration and transparency: - Consolidate fiscal responsibilities in tax administrations where feasible; ensure NEICs are taxed and audited like private firms. - Strengthen royalty administration (annual returns, reconciliation with commercial accounts). - Publish fiscal terms, contracts, and revenue flows to deter corruption and improve investor confidence. - Tackle international tax and transfer pricing vulnerabilities: - Design treaty policy and anti-treaty-shopping rules mindful of base erosion risks. - Implement industry-specific transfer pricing guidance and robust data collection for audits. - Use competitive allocation (auctions) where sufficient bidder information exists; avoid excessive reliance on high fixed upfront bids that risk investor viability under realistic discovery probabilities. *Source: IMF staff paper, "EI Revenue Potential: Selected African Countries."* ### 1. EI Revenue Potential: Selected African Countries ................................................................8 ### 1. EI Revenue Potential: Selected African Countries ### Executive Summary — key findings and benchmarks - The extractive industries (EI—oil, gas, and mining) often account for over half of government revenue in petroleum-rich countries, and for over 20 percent in mining countries. - Dependence on EI revenues in resource-rich countries is now about one-third of the Fund’s membership. - Data analyzed suggest that in mining, governments commonly retain one-third or rather more; simulations suggest higher government shares of 40–60 percent, though these simulations do not capture all possible sources of revenue erosion. - Simulations suggest that the government share is higher in petroleum: around 65–85 percent. - Fiscal regimes that raise less than these benchmark averages may be cause for concern, or—where agreements cannot reasonably be changed—regret. - A regime combining a royalty and a tax targeted explicitly on rents (along with the standard corporate income tax) has appeal for many developing countries: - ensures some revenue at the start of production; - government revenue rises as rents increase with higher commodity prices or lower costs; - can enhance stability and credibility of the fiscal regime; - balances administrative challenges across instruments. - Effective administration is vital; complex EI fiscal regimes and fragmented responsibilities are often major impediments. Royalties need not be as easy to administer, nor rent taxes so hard, as is sometimes believed. - Poorly designed international tax arrangements can seriously undermine revenue potential. - Transparent rules and contracts tend to improve stability and credibility; processes to allow renegotiation may also be needed. ### Introduction — scope and purpose - The paper considers how best to realize the revenue potential of the EIs, particularly in developing countries, and sets out the conceptual approach and techniques guiding IMF staff advice. - Designing and implementing upstream fiscal regimes for the EIs is a major focus of IMF policy support and technical assistance (Appendix II). - Recent and prospective discoveries (oil, gas, iron ore, shale gas, rare minerals) amplify the macroeconomic significance of EI and make fiscal regime design a key challenge and opportunity for many developing countries. ### Selected country/project revenue potentials (Table 1) - Notes: Estimates are intended to show order of magnitude. Revenue projections are highly sensitive to assumptions about prices, phasing of production, and underlying production and capital costs. Data represent annual revenue at peak production where noted. - Ghana, Jubilee (Phase 1 only) - Mineral: Petroleum - Investment US$bn: $3.15bn - Average annual revenue potential (US$bn, constant 2011 dollars; percent 2011 GDP): $0.85bn; 2.3 - Lifespan of project(s): 21 years - Guinea, Simandou, and others - Mineral: Iron ore - Investment US$bn: $4bn for mining project [with additional $6bn in railway and port infrastructure] - Average annual revenue potential: $1.6bn; 30.7 - Lifespan: 21 years - Liberia - Mineral: Iron ore, petroleum - Investment US$bn: $4.5bn - Average annual revenue potential: $1.7bn; 147.8 - Lifespan: 20–30 years iron ore; potential 20+ for petroleum (but no proven project yet) - Mozambique, Rovuma (gas) Tete (coal) - Mineral: Gas and coal - Investment US$bn: $20-30bn - Average annual revenue potential: $3.5bn; 27.3 - Lifespan: 30–50 years - Sierra Leone, various - Mineral: Iron ore, petroleum, diamonds - Investment US$bn: $4.6bn - Average annual revenue potential: $0.4bn; 18.2 - Lifespan: 15 years - Tanzania - Mineral: Gas, Gold, Nickel - Investment US$bn: $20-30bn - Average annual revenue potential: $3.5bn; 15.0 - Lifespan: 10–20 years gold (remaining in existing mines); 20–30 gas and nickel - Source: IMF staff estimates. ### Revenue potential from oil and related calculations - Gelb, Kaiser, and Viñuela (2012) estimate exploration and development costs at $6–14 per barrel for East Africa. - Applying costs across sub-Saharan Africa with oil at $80 per barrel and assuming governments secure 50 percent of the excess of price over cost (and many regimes in the region seem likely to capture more), increasing production by 1 million barrels per day would increase government revenue in the region annually by about $12 billion, or 1 percent of the 2011 GDP of sub-Saharan Africa. - Angola increased production by 1 million barrels per day over 2001–11 while more than doubling its proven reserves. - Sub-Saharan Africa increased proven reserves by 50 percent over 2001–11 (to 68 billion barrels); the increase in daily production over 10 years could well exceed 1 million barrels. - In iron ore, sub-Saharan Africa has reserves that can provide an estimated 120 years of total world supply (out of about 500 available globally). If all these reserves could be developed and government revenue were apportioned over 500 years, annual revenue addition would be about 0.7 percent of the region’s 2011 GDP. ### Trade-offs, instruments, and administration - Revenue objectives are central in designing EI fiscal regimes but involve complex trade-offs with other objectives (employment, environmental impacts). - The prospect of substantial rents—returns in excess of the minimum required by the investor due to relative fixity of supply—makes EIs attractive as a revenue source. - Fiscal regimes for the EIs vary greatly; a wide range of instruments are used. - Combining a royalty, a rent-targeted tax, and corporate income tax can: - provide early revenue flows (royalty); - allow government revenue to rise with rents (rent tax); - balance administrative challenges. - Transparent rules and contracts improve stability and credibility; renegotiation procedures may be necessary. - Effective tax administration and coherent responsibilities are critical; complex regimes and fragmented responsibilities are common impediments. - International tax arrangements and poor design can seriously undermine domestic revenue potential. *Source: IMF staff paper, "EI Revenue Potential: Selected African Countries."* ### 5. Country-level simulations confirm this potential. The interaction of geology, ### _081512 - 5. Country-level simulations confirm this potential. The interaction of geology, ### Country-level simulation finding - Using crude assumptions for sub-Saharan Africa, discovery and development of a single additional oil field in each of at least 18 countries with petroleum potential would add in a year nearly 2 percent of collective GDP to the revenue of these countries in the peak production years of these fields. - The country-by-country impact differs widely. - Natural gas may have similar potential. ### Central fiscal issue: government share of rents - ‘Rents’ defined as the excess of revenues over all costs of production, including those of discovery and development, as well as the normal return to capital. - Rents can, in principle, be taxed at up to 100 percent without making the activity privately unprofitable, but substantial obstacles make this effectively impossible. - By ‘reasonable’ sharing is meant at least providing private investors with an adequate incentive to explore, develop, and produce. ### Distinctive, tax-relevant characteristics of extractive industries (EIs) - Potentially sizable rents arise; attractive tax base on efficiency and equity grounds. - Pervasive uncertainty: - Major uncertainty on commodity prices (see Figures 1 and 2 referenced). - Substantial uncertainty also from geology, input costs, and political risk (including expropriation and changes in future fiscal regimes). - Asymmetric information: private investors often better informed on technical/commercial aspects; host governments better informed on future fiscal intentions. - High sunk costs creating time-consistency and “hold-up” problems. - Extensive involvement of multinational enterprises raises complex tax issues. - State-owned enterprises (SOEs) involvement can ease asymmetric information but raise efficiency and taxing-responsibility concerns. - Market power: examples include iron ore supplies concentrated in three companies and Saudi Arabia’s influence on oil prices. - Exhaustibility: importance to long-term macro performance is questionable, but at project level exhaustibility is a key concern; extracting today foregoes future extraction. - Sectoral differences: - Exploration often costlier and riskier for petroleum (a deep water well, for instance, can cost over US$100 million, and the chance of success in a new basin may be 1 in 20 or less). - Mining may face greater development and extraction-phase failure risk and greater political/environmental risks (typically land-based). - Commercial structures differ: unincorporated joint ventures (UJV) common in petroleum; less common in mining. - Technological and market changes: - ‘Fracking’ enables fuller exploitation of onshore unconventional oil and gas. - In copper mining, new techniques have increased processing efficiency despite declining ore grades. - Transparency agenda is transforming expectations of private companies and host governments. - Resource-rich countries differ widely in ways relevant to tax design: number of projects, existing contractual constraints, pace of exploitation, constitutional/state-participation constraints, cross-border fields, administrative capacity, and governance standards. - Artisanal mining: often large in some developing countries; fiscal treatment suggested is to levy royalties via requiring traders to withhold and pay, rather than taxing miners directly (except for a small license fee). ### Objectives for fiscal regimes for EIs - Primary objective: maximize the present value of net government revenues from EI—best served by taxes explicitly targeted on rents. - Limits and obstacles to taxing rents fully: - Asymmetric information requires governments to forego some rents to provide investor incentives. - Practical difficulties in observing revenues and costs; tax avoidance devices. - Need to account for costs at all stages, including unsuccessful exploration; quasi-rents after sunk exploration/development costs cannot be taxed at 100 percent without making ventures ex ante unprofitable. - Tax competition: limited technical expertise and equipment may favor jurisdictions offering more favorable tax treatment. - Timing of receipts matters: - Governments with limited credit access or political preference may favor early revenue. - Willingness to defer revenue (lower royalties, accelerated depreciation, greater reliance on rent taxes) may reduce perceived investor risk and lower required expected returns. - Risk-sharing and progressivity: - ‘Progressivity’ defined roughly as extent to which revenue increases as commodity prices rise or production costs fall. - Efficiency requires risk be borne by the party better able to bear it; in many developing-country contexts this may be private investors who can diversify. - This suggests fiscal regimes that are not highly responsive to commodity prices (investor gets most upside; government protected on downside). - Limited progressivity conflicts with desire for revenues to increase with current prices; progressive regimes may be politically more robust and credible. - A more diverse portfolio of projects reduces the risk-sharing argument against progressivity. - Ease of administration and compliance is an overarching concern. - Governments differ in prioritization of these objectives depending on number of projects, credit market access, alternative revenue sources, and political pressures. ### Overall fiscal schemes for EIs - Two main approaches: - Contractual schemes (including production sharing or service contracts). - Tax/royalty systems with licensing of areas (dominant in mining; both used in oil and gas; hybrids exist). - A third approach is payment largely as construction of physical infrastructure. - Case-by-case negotiation can occur under either contractual or tax/royalty schemes. - Historic pattern: tax and royalty schemes prevailed with remaining business income subject to normal business taxation; developing countries often used contractual schemes to express sovereignty or attract private investment. - Contractual schemes commonly developed where national oil companies (NOCs) had monopoly rights and contracted foreign providers; production-sharing initiated in mid-1960s (Indonesia cited as pioneer). ### Representative numeric and illustrative values cited - At least 18 countries: additional single oil field in each could add nearly 2 percent of collective GDP to revenues in peak years. - CIF iron ore price example used in staff calculations: $107 per ton. - Overall costs example: $70 per ton. - Government share of surplus over costs example: 40 percent. - Deep water well example cost: over US$100 million. - Chance of success in a new basin example: 1 in 20. - Rents can, in principle, be taxed at up to 100 percent. *Italic: Source: Extracted content from the supplied IMF chapter/section.* ### 25. Under production sharing contracts (PSC), common in petroleum, a contractor ### 25. Under production sharing contracts (PSC), common in petroleum, a contractor ### Forms of production sharing and variants - Under PSCs a contractor recovers costs by retaining some of the physical product as “cost oil/gas” and the remaining “profit oil/gas” is shared with the government. - Leading variants aimed at increasing the government’s profit share on more profitable projects: - Daily Rate of Production (DROP) - Government share of profit petroleum increases with the daily rate of production from the field or license, often with several tiers. - Weaknesses: field size is often a poor proxy for profitability; mechanism is not progressive with respect to oil prices or costs. - Attempts have been made to blend this with a scale of prices. - Cumulative production from project - Government share of profit petroleum increases as total cumulative production increases. - Weakness: an inaccurate proxy for the contractor’s rate of return. Such schemes are becoming rarer. - “R-Factor” - Government’s profit share increases with the ratio of contractor’s cumulative revenues to contractor’s cumulative costs (the “R factor”). - Improves on DROP by being a more direct measure of profitability but does not recognize the time value of money (Box 2). - Rate of Return (ROR) - A form of rent tax (provided that exploration is part of costs) under which the government’s share is set by reference to the cumulative contractor rate of return; no tax is levied if that falls short of some benchmark rate. - Single or multiple tiers are used; staff analysis suggests a single tier is effective. ### Design principles and practical considerations for fiscal regimes - Staff advice applies within both royalty/tax frameworks and PSC frameworks; emphasis on: - Design to achieve fiscal efficiency. - Regime transparency. - Choice of overall framework determined by institutions, tradition, and non-financial objectives. - Companies operate within both schemes; major oil companies tend not to favor contractual forms unless these permit “booking” of reserves under stock exchange rules. - PSCs sometimes preferred because they fill legal gaps and provide one comprehensive document covering operations; same objective achievable with a petroleum agreement under a tax and royalty system. ### Infrastructure contributions and resource investments - Renewed popularity of resource investments coupled with infrastructure contributions presents valuation challenges. - Principle: require cost-benefit analysis valuing infrastructure contributions with risk apportioned to assess whether they offer payment for resources equivalent to likely take from any foregone royalty or tax. - In practice, arriving at such assurance is difficult. ### Fiscal instruments for extractive industries (EI) - Wide range of instruments; design considerations summarized below (administration and compliance addressed in Section III of source). - Bonuses (signature, discovery, production) - Single (or staged) lump-sum payments triggered by events; can be legislated or negotiated and biddable. - Examples: top bid over $1 billion in Angola’s 2006 round; much more modest in USA offshore auctions. - Signature bonuses become a sunk cost for companies and may pose political risk if a project is especially profitable. - Royalties on gross revenues - Attractiveness: provide government revenue from start of production. - Drawbacks: as a simple addition to cost, can render extraction of some deposits unviable; act as implicit depletion policy and invite negotiation. - When royalties are a major part of regime, they tend to become more complex to respond to profitability via proxies (price, location, production level). - Royalty rates that vary with price do not vary with costs and thus may not be appropriate across the marginal cost curve; price-based scales require frequent adjustment when forecasts are wrong. - Royalty rationalization: can correct for possible overexploitation, though practical importance unclear; government can charge a royalty reflecting diminution in terminal value to correct firm’s misalignment with social interest at end of contract. - Gross royalties protect revenue against overstatement of cost but can weaken government position if little knowledge of costs; companies can increase deductible costs to reduce profit-related taxes. - “Net profits” royalties and related schemes function more like income taxes; the name may persist due to attribution to sub-national tier. - Corporate Income Tax (CIT) - Core component of most EI fiscal regimes; ensures normal return to equity is taxed at corporate level as in other sectors. - Some countries apply higher-than-standard CIT rates in EI (e.g., Indonesia in mining; Nigeria and Trinidad and Tobago in petroleum). - Variable Income Tax (VIT): uses CIT base but varies the rate according to ratio of profits to gross revenues; relatively simple but may introduce distortions (e.g., high tax rate early in project life before required return earned) and may increase debt-bias unless interest deduction is limited. - Resource rent taxation - Rents-targeting taxes increasingly used in petroleum and mining. - CIT is a blunt instrument for taxing rents because it taxes full return to investors including required return to equity; high CIT can discourage investment by increasing required pre-tax return. - CIT is biased toward debt-financing because interest is deductible while cost of equity capital generally is not. - Royalties and other instruments also cause distortions that erode pre-tax rents. - Rent taxes aim to preserve surplus and transfer substantial part to government; alternative forms differ importantly in timing of government receipts. ### Box 2 — Two leading forms of rent tax (summary) - Brown Tax (R-based cash flow tax) - Base: all current receipts less all current expenses (both non-financial). - Immediate refund (or carry forward at interest) when negative. - No accounting/tax depreciation—capital immediately expensed; no deductions for interest or other financial costs. - Variants: - Resource rent tax: replicates many Brown Tax features; investor receives annual uplift on accumulated losses until recovered (uplift rate originally set at minimum required rate of return; choice now widely questioned). Australia uses this scheme for mining and petroleum; Angola’s PSC uses mechanism. Usually applied with ring-fencing by license. - Tax surcharge on cash flow: adjusting accounting profit by adding back depreciation and interest and deducting any capital expenditure in full yields base of net cash flow; could form base for a surcharge. Variant includes limited-time uplift (UK uses time-limited uplift on losses). In the UK, surcharge combined with conventional CIT within sector-wide ring fence. “R-factor” or payback ratio scale and Indonesian “investment credit” are further variants. - Allowance for Corporate Equity (ACE) or Capital (ACC) - ACE: amends standard CIT by providing deduction for imputed return on book equity; tax depreciation remains but faster depreciation reduces equity and hence future deductions by an offsetting amount. - ACC: gives interest deduction at a notional rate, eliminating distinction between debt and equity finance. - Norway’s special petroleum tax approximates ACC, with combination of uplift on total investment and limitation on interest deduction and refund of tax value of exploration losses and ultimate losses on licenses. - Timing difference: tax payments generally earlier under ACE/ACC than Brown Tax. Under Brown Tax tax payable when costs fully recovered; under ACE/ACC payable roughly when annual income covers annual cost of financial capital. - Key contentious issue: choice of imputed rate of return (for loss carry forward under Brown Tax and for capital costs under ACE/ACC). ### Practical use and prevalence of instruments - Staff advice in developing countries often to combine a rent device (Box 2) with a royalty to form combined “resource charge”; balance determined by relative ability to bear risk and government tolerance for revenue delay. - Measures that bring forward revenue increase investor risk and may ultimately diminish taxable rent. - State equity used by many countries to secure additional government take: - Motivations can be non-fiscal (direct government ownership, “seat at the table,” knowledge transfer) but regulation can achieve similar benefits. - Forms of state equity: - Fully paid-up equity on commercial terms (puts government akin to private investor—akin to Brown Tax). - Carried interest: private company finances government participation with cost offset against future state share—equivalent to Brown Tax. - Free equity: government negotiates free equity—equivalent to dividend withholding tax (DWT) as a charge on profits; usually leads to some offset against other tax payments. - Instrument choice in practice: wide variation; little evidence on relative yields. - Staff sample: 25 mining regimes and 67 petroleum regimes analyzed. - Key observations from sample: - In mining, royalties ubiquitous; production sharing and bonuses absent. - In petroleum, one-sixth of cases have no royalties, nearly one-half have production sharing, just under 20 percent have bonuses. - Even where mining royalty regimes exist, there is considerable variation in precise form. - Table 3 (summary of prevalence by number of countries in staff sample): - Sample size: Number of countries — Mining: 25; Petroleum: 67. - Signature bonus: Mining 1; Petroleum 16. - Production bonus (fixed payment on achieving cumulative production or production rate): Mining None; Petroleum 10. - Royalties: - Specific (amount per unit): Mining 2; Petroleum 1. - Ad-valorem (percentage of product value): Mining 17; Petroleum 31. - Ad-valorem progressive with price: Mining 1; Petroleum 9. - Ad-valorem progressive with production: Mining (blank) ; Petroleum 8. - Ad-valorem progressive with operating ratio/profit: Mining 3; Petroleum 1. - Royalty applied to operating margin (net profits royalty): Mining 2; Petroleum 0. - State/provincial/local CIT: Mining 1; Petroleum 2. - Variable income tax: Mining 3; Petroleum 2. - Resource rent taxes (cash flow with accumulation rate/uplift): Mining 5; Petroleum 5. - Cash flow with limited uplift on losses (UK surcharge): Mining None; Petroleum 2. - Allowance for Corporate Capital: Mining None; Petroleum 1. - Allowance for Corporate Equity: Mining None; Petroleum 1. - Other additional income taxes: Mining 1; Petroleum 3. - Production sharing: Mining None; Petroleum 5. - R-Factor: Mining None; Petroleum 13. - Rate of return, pre- or post-tax: Mining None; Petroleum 3. - Production level: Mining None; Petroleum 13. - State participation: - Free equity: Mining 2; Petroleum None. - Carried equity: Mining 3; Petroleum 8. - Paid equity: Mining None; Petroleum 19. - Social investments/infrastructure: Mining 1; Petroleum 6. - Source of table data: IMF FARI Database (as presented in source). - Figure 3 examples of revenue composition (as compiled for paper): - Oil (Chad, 2010): Royalty 28%; Statistical fees 3%; Income tax 69%. - Copper (Chile, 2009): Royalty 4%; Income tax 29%; Revenue from state-owned company 67%. ### State control and taxation scope - Some 80 percent of world petroleum reserves are controlled by state companies and 15 of the 20 largest oil companies are state-owned. - In these cases government (or NOC) pays for private services it contracts and sometimes uses service contracts to approximate PSC risk-reward arrangements. - Except for Iraq’s contracts, these systems do not allow private firms to “book” reserves under SEC rules—for which they will seek compensation. - Several G20 and high-income countries have scope to tax EI rents more effectively; Box 3 summarizes issues and experiences. ### Tax effects on exploration, development, and extraction - Taxation affects decisions at all stages—exploration, development, and production—including: - Intensity of exploration. - Timing and intensity of initial development. - Timing and intensity of extraction and enhanced/secondary recovery. - Eventual abandonment of the mine or oil field. - No single model covers all dimensions satisfactorily; Smith (2012) develops a framework (Appendix V) to analyze behavioral impact of tax design over EI lifecycle. - Simulations in Smith (2012) highlight a range of considerations (model designed/calibrated for oil and gas but adaptable for mining). ### Box 3 — EI fiscal regimes in higher-income countries (high-level summary) - Recent debates and reviews in Australia, Brazil, United States, Russian Federation indicate design weaknesses are not limited to developing countries. - Movement toward explicit rent taxation and use of auctions could produce marked revenue enhancement. - Country examples summarizing fiscal choices: - United States: auctions with bonus bidding for Outer Continental Shelf + CIT + royalties; onshore and mining often use gross revenue royalties (net profit royalties common in some states). - Russia: complex/distorting system combining royalty, export taxes, and different domestic/export prices. - Canadian provinces: move toward profit or cash flow related taxes on oil and gas (still often called “royalties”). - Norway: closest to pure rent tax (ACC form) coupled with CIT; system noted for stability. - United Kingdom: began with complex/frequently changed system; in recent years used cash flow tax as surcharge to CIT; both U.K. and Norway effectively refund tax value of losses. - Australia: explored differing approaches; history includes PRRT for offshore petroleum (deductible for CIT), state royalties and CIT for onshore/mining, and 2010 Henry Proposal (Allowance for Corporate Capital variant) later replaced by Minerals Resource Rent Tax (MRRT) applying to iron ore and coal at effective 22.5 percent rate after uplift on cash outflows of LTBR plus 7 percentage points, and allowing crediting of state royalties; PRRT extended to onshore activities. *Source: Excerpt from IMF document section on fiscal regimes for extractive industries (as provided).* ### 41. The impact on exploration depends on the total government take in the event of ### 41. The impact on exploration depends on the total government take in the event of ### Impact on exploration decisions - Decision to explore compares fixed cost of drilling with: - the probability of success (updated as exploration progresses), and - the return conditional on successful discovery. - Simulations in Smith (2012) suggest that a tax regime with government take of approximately 50 percent of quasi-rents in the event of success (ring-fenced, so that exploration costs do not attract immediate tax reduction) reduces the acceptable number of exploratory failures appreciably, by 15–25 percent. ### Royalties and production-sharing agreements (PSAs) - Royalties and PSAs that create effective royalties can plausibly cause significant distortion: - A 20 percent royalty or a 40 percent minimum profit oil share to the state (allowing only 50 percent of available oil for production costs) reduce initial investment by some 20 percent and the extraction rate by approximately 1 percentage point per year. - The same terms delay investment in enhanced recovery by 1 or 2 years, with a further overall investment reduction of 20 percent. ### Resource rent tax incentives and risks - A resource rent tax may increase investment if the uplift rate on capital expenditure exceeds the company’s cost of capital, creating: - a negative marginal effective tax rate, and thus an implicit subsidy to resource extraction (Mintz and Chen, 2012). - an incentive to “gold plating” (inflating costs) or suboptimal timing of investment (sooner rather than later). - The strength of this incentive depends on both: - the excess of the uplift rate over the cost of capital, and - the resource rent tax rate; where both are low, the incentive is small (Appendix IV). ### Tax effects over the full project cycle - Tax effects must be considered over the full project cycle due to sequential interactions: - Distortions at one stage impose distortions at others. - High royalty rates are associated with longer production lifetimes because: - expectation of high royalty rates leads to lower development investments, implying higher marginal extraction costs, - total extraction over the expanded lifetime remains smaller than without the tax. - Effects can be more subtle than the direct taxation of quasi-rents on exploration. ### FARI model (FAD’s Fiscal Analysis of Resource Industries) - Description and capabilities: - Excel-based model enabling detailed design, modeling, and comparison of fiscal regimes across the entire lifecycle of petroleum or mining projects. - Increasingly used as a forecasting tool linked to the macro-economic framework for resource-rich countries. - Does not incorporate behavioral responses of the kind discussed, though extensions can simulate tax effects on investors’ perceived risk (see Appendix VI). - Key output: - Average Effective Tax Rate (AETR): government’s share of pre-tax net present value (NPV), usually measured at the government’s assumed discount rate. - Illustration (Figure 4) reports estimated AETRs showing most petroleum fiscal regimes have higher AETR and more progressive elements than mining regimes. - Project example parameters reported in Figure 4: - Petroleum: Field: 300 MMBbl; Size: 298 MMBOE; Costs: $21.0 BOE; Oilprice: $100 Bbl; IRR pre tax: 56% - Mining: Project: Iron Project small; Size: 76.7 MM tonnes; Unit costs: ConstReal $41; Iron Ore FOB price: ConstReal $80; IRR pre-tax: 44.4% ### Evaluation of alternative fiscal regimes - Table 4 evaluates several mechanism families against government objectives (matching instruments to objectives using FARI results). - No regime is ideal for all circumstances. - For LICs, combining the following has considerable appeal: - a modest ad valorem royalty, - CIT, - resource rent tax. - Rationale: - Royalty ensures some revenue whenever production is positive. - CIT ensures normal return to equity is taxed at corporate level and permits foreign tax credits where applicable. - Resource rent tax exploits distinct revenue potential of extractive industries. - Additional design notes: - Competitive allocation of licenses/contracts may allow a bonus or a fiscal parameter to be a bid variable (bidding affects design of fixed tax elements). - Interactions between CIT and rent tax mean the latter, even if deductible from the former, in general ceases to be neutral. - Suggested target ranges from simulations: - Mining: AETRs of 40–60 percent. - Petroleum: AETRs of 65–85 percent. ### Administration of EI fiscal regimes - Administrative challenges and observations: - EI fiscal regimes are often simpler in that outputs can be measured and prices are often quoted on international exchanges, yet administration is often difficult and badly performed. - Variety and complexity of regimes pose serious challenges; important tax rules often complex, unclear, or open to abuse. - Even with few EI companies, routine processing and reporting are often hampered; royalty administration is often particularly inefficient (frequent assessments, no annual return, no reconciliation to commercial accounts and CIT returns). - Fragmented administration prevents coherent risk-based audit and taxpayer service functions; pay, status, and authority for operational staff often inadequate. - Institutional recommendations: - Consider changing responsibilities of EI ministries and national EI companies (NEICs) to avoid fragmented tax-type-based administration and conflicts of interest. - Separate fiscal roles from regulatory and commercial roles; placing fiscal roles in the tax department is the most obvious and effective approach. - EI ministry may retain responsibility for physical audit (consistent with regulatory role); sharing physical audit information with tax administration is vital. - Royalties vs. profit/rent-based taxes: - Royalties are not always easier to administer; valuation can be technically demanding (especially for mining), and “netback” valuation poses challenges. - Profit/rent-based taxes are not necessarily harder; many LICs apply CIT to complex activities and rent taxes (e.g., R-based cash flow tax) can simplify calculations by avoiding depreciation, financial costs, or gains on license transfers. - Angola successfully applies production-sharing scaled to internal rates of return despite capacity constraints. - Principles for effective administration: - Simple, well-designed legislation with minimum number of taxes. - Integrated, function-based organizational structure. - Coherent, self-assessment-based procedures. - Taxpayer-focused compliance risk management. - FAD technical assistance: - Strengthening EI revenue administration is an increasing focus of FAD TA; immediate gains available from simple steps to improve audit (Appendix VII). ### Transparency - Risks and current shortcomings: - Resource wealth can undermine governance; transparency in tax policy design and administration is often lacking. - One-off confidential agreements, contract confidentiality, fragmented filing and payment procedures, revenues paid in kind, and no single department responsible for accounting create opacity. - Initiatives and limitations: - Extractive Industry Transparency Initiative (EITI) requires companies to publish payments and governments to publish receipts, audited and reconciled; confidentiality barriers must be removed. - Section 1504 of the US Dodd-Frank Act requires SEC-listed EI companies to report payments to governments; similar disclosure proposed in EU Transparency Directive. - EITI has led to progress, but some countries publish one-off tax agreements without moving to taxation based on published legislation; government accounting remains poor. - Reference: - IMF’s Guide on Resource Revenue Transparency (2007) considers the issues comprehensively. ### Revenues from extractive industries (EIs) - Data limitations: - Data on government revenues from the EIs are poor; an IMF initiative aims to improve them. - Difficulties include sector-specific and conventionally “non-tax” instruments, identifying resource-related components of CIT and other instruments, and fragmented data collection. - Discussion uses data provided by country desks on 57 resource-rich countries for 2001–10 (Appendix IX). - Magnitude and reliance: - Government revenue from EIs is substantial in many countries, with reliance especially high in some developing countries. - Petroleum revenue can be especially large: over 10 percent of GDP in 22 countries. - Dependence examples: - Petroleum revenues accounted for about 93 percent of all government revenue in Timor-Leste (2008). - Petroleum revenues accounted for around 82 percent in Angola (2007). - Aggregate patterns illustrated in Figures 5–7 (2001–10) showing country-level average revenue as percent of GDP and percent of total revenue. *Source: IMF staff estimates.* ### 62. Revenues from the EIs increased over the past decade, most consistently in ### _081512 - 62. Revenues from the EIs increased over the past decade, most consistently in ### Revenues from extractive industries (EIs): trends and magnitudes - Revenues from petroleum rose in the countries shown from an average (GDP-weighted) of 8 percent of GDP to 12 percent, and from 26 percent of government revenue to 35 percent. - EI exports rose from a weighted average of 7.7 percent of GDP in 2001 to 12.3 percent in 2010. - Petroleum’s share of these exports decreased from 93 percent to 87 percent over the same period. - For mining countries: increase in revenue less marked relative to GDP, but much greater (and very volatile) relative to all government revenue, reflecting that mining-intensive countries are relatively low income and tend to have fewer alternative revenue sources. - Revenues in both sectors appear to have moved more or less in line with commodity prices; mining revenues tracked less the strong rise in gold prices than the evolution in prices of other main metals (copper, aluminum, iron ore, tin, nickel, zinc, lead, and uranium). - Simple regressions do not show revenues to be strongly progressive in current prices, though detection is difficult because price movements may affect the denominator of the revenue/GDP ratio. ### Effective tax rates on EI activities: methods and findings - Two complementary methods elaborated in Appendix IX: simulation methods (using the FARI model) and analysis of accounting data; each method has strengths and weaknesses. - Simulation exercises can take full account of all taxes over a project’s lifetime but require projecting future prices and costs and may overstate effective tax rates by not capturing all sources of revenue erosion (e.g., through imperfect administration). - Accounting data reflect actual outcomes but provide only a snapshot across a miscellany of activities. - Staff also experimented with a third method comparing companies’ actual market values with post-tax expected values given reserves and current costs and prices, but further work is needed to have reasonable confidence in results. - Indicative effective tax rate ranges from the exercises: - Petroleum: around 65–85 percent. - Mining: 45–65 percent. - Effective tax rates increase with earnings, most markedly for petroleum. - Possible reasons for higher effective rates in petroleum than mining: - Expectation of rents and fiscal regimes shaped to capture them may be longer established for petroleum. - Perception of greater non-fiscal benefits from mining (especially relative to offshore oil) may lead to more intense tax competition. - Asymmetric information on exploration and development risk and related administrative challenges may be greater in mining (absence of spot prices for some commodities, for instance). - Future prospects: potential for substantial supply in minerals that could dilute rents, whereas in petroleum restricted access to reserves and increasing costs of marginal production (Canadian oil sands or ultra-deep water) may mean significant rents for lower cost producers will remain. ### Stability, credibility, and design of EI fiscal regimes - Stability and credibility of the fiscal regime are critical to overcoming the hold-up problem; they do not necessarily require contractual fiscal stability assurances. - Predictability is needed not only for the fiscal regime itself but also for the process and/or criteria by which a regime may be modified. - Stability assurances can have strengths and weaknesses similar to fiscal rules: - They can bind all parts of government and future governments or serve as signaling devices to encourage investors. - They can also function as a “smokescreen” if the government intends less visible changes to other legal arrangements over time. - The value to investors is not always clear; invoking an assurance may indicate already-broken relations. - General legislation versus case-by-case negotiation: - Legislating terms applicable to all EI projects can reduce administrative costs, political difficulties, and perceived investor risk. - Setting terms in a model agreement may turn them into negotiation bases rather than fixed rules. - Advantages of case-by-case negotiation for governments are frequently exaggerated; investors often have superior information on prospective profitability. - General fiscal terms have been used successfully in countries attracting substantial mining investments: Australia, Canada, Norway, Bolivia, Brazil, Chile, Indonesia, Namibia, Peru, and South Africa. - Publication of negotiated outcomes deters corruption and is more likely to produce sustainable, mutually beneficial outcomes. - Renegotiation: - Renegotiations do and sometimes should occur—warranted when terms become egregiously out of line with international practice or comparable circumstances. - When renegotiation occurs through consultation or mutual agreement, the investment climate may be strengthened. - Contract schemes increasingly include provisions for periodic reviews. ### International tax issues for EIs - International tax issues for EIs merit more attention and arise with special force in EIs though many are not EI-specific. - Transfer taxation on sale of interests in mining or petroleum rights is pressing and controversial: - Large gains were achieved by sellers in exploration project transactions (examples cited: Ghana and Uganda). - The tax amount at issue in one Ugandan case was around $400 million. - Tax treaties can erode the EI tax base: - They frequently reduce permitted levels of border withholding taxes (WHTs) or eliminate them. - “Treaty shopping” can substantially reduce WHT obligations on dividends, interest, and management or technical service fees. - Developing countries with substantial EI inflows and negligible outward investment need treaty strategies that minimize base erosion and consider rules against treaty shopping. - Transfer pricing vulnerability: - Higher taxes on upstream activities increase transfer pricing risk; companies are often integrated multinationals and tax haven use is common. - Mitigating features in EIs: observable physical operations and outputs, standard measurements and benchmark international prices, and (in petroleum) joint venture structures that help control costs. - Good practice: clear, transparent transfer pricing rules approximating arm’s length prices, using industry-specific practices and upstream input/output values; the onus is on the taxpayer to comply and demonstrate compliance. - Published benchmark prices should be used where available; tax authorities need vigorous data collection to support risk-based audits. - Regional coordination: - Potentially worthwhile but likely less urgent for EI fiscal regimes than for other business taxation aspects. - Downward pressure on tax rates to attract scarce exploration and development capacity is a concern; regional agreements could allow countries to levy royalties and rent taxes appropriate to their prospectivity and cost structure. - Committing to maximum tax rates (not just minimum) could help overcome time consistency problems. - Coordination issues are less pressing than those relating to tax incentives for more mobile activities. ### Taxation and the granting of rights; auctions - Taxation is linked to how mineral rights are granted; separating exploration from extraction may benefit governments (e.g., auctioning known deposits to the highest bidder) provided prior extraction rights were not created during exploration. - Companies typically will not invest in exploration without assurance of extraction rights in case of success, but deposits are sometimes relinquished and government acquisition of exploration data can increase feasibility of competitive licensing. - Auction design is critical: - Greater success in auctioning petroleum exploration awards than other EI activities, possibly because more data from adjacent finds encourages competition. - Bid variables may include bonus payments and/or other items; key is not to impose too many variables or criteria. - Auction procedure choice depends on circumstances (sequential vs simultaneous sale; dynamic vs static auction; information policy; reserve prices). - Auctions are unlikely to succeed without sufficient participation by qualified bidders and measures to avert collusion. - Bidding can be combined with taxation (a future contingent payment liability); fiscal regime structure is integral to auction design and revenue potential. ### Key points from consultations with Civil Society Organizations (CSOs) and EI companies (Appendix I) - Civil Society Organizations (CSOs): - Need for strong tripartite partnership between CSOs, government, and private sector; CSOs usually have limited sector knowledge and donors and the IMF should help build CSO capacity. - IMF should support CSOs’ efforts to bring transparency through disclosure of contracts and tax collection from EI projects. - IMF should support governments in implementing effective tax collection policy and auditing. - Natural resources represent an injection of funds but not necessarily growth for resource-rich communities. - Public policy should address natural resources’ limitedness and the need to serve future generations. - Royalties have many disadvantageous features for host government; income taxes offer more positive benefits but require capacity building to monitor abusive transfer pricing. - IMF should propose allocating a percentage of taxes collected from extractive activities directly to involved local communities (but empirical evidence on earmarking to provinces is mixed). - Rents need to be shared fairly among companies, national governments, and regional governments; promote transparent, balanced, progressive, and environment-friendly tax regimes to avoid corruption and revenue erosion. - EI companies — Mining: - Focus on division of rents and on broader economic and social impact of mining. - Resource revenues should support improvements in institutions and administrative capacity. - Competition among companies can lead to over-investment and enhanced price volatility. - Risk profile of projects is as important as expected NPV. - Governments have seen the largest increases in returns since 2005; mining companies use higher profits to fund future investments; substantial cash on balance sheet does not mean a company is under-taxed. - Auctions maximize value only when sufficient knowledge about the resource base exists (less common in mining than petroleum). - Tax system should be predictable and substantially profit-related, with no retrospective imposition of taxes. - EI companies — Petroleum: - Exploration risk is large and many discoveries remain uneconomic. - Commercial success rate is influenced by fiscal terms, though not solely determined by them. - Sector is changing as exploration moves to deeper water and unconventional gas and oil sources, with longer timelines and sometimes higher risks. - The average government take worldwide for oil and gas projects is around two-thirds, and the sector is not under-taxed. - Oil companies need clear, stable, and simple fiscal regimes. - Gas and oil prices have increasingly diverged and fiscal regimes have not taken this into account. - Companies’ analysis includes balancing risk with governments, avoidance of double taxation, and the ability to tax-deduct expenses. - Auctions have had mixed success; some secured unsustainable bids. Bonuses are problematic because they often cannot be claimed as tax deductions; auctions on production targets or contingent payments might be preferable. - Royalties or levies on gross production distort investment and production decisions. ### Technical assistance on EI fiscal regimes (Appendix II) - Over the last seven fiscal years (2006–12), staff delivered around 85 TA missions in 37 countries that involved taxation of natural resources—approximately half of these in 2011 and 2012 alone. - Number of missions by year: - 2006: 6 missions. - 2012: 31 missions. - The increase in 2012 substantially reflects the start of the Topical Trust Fund on Managing Natural Resource Wealth (MNRW TTF); 2011 already saw a steep rise to 15 missions. - There are already 33 HQ-led missions on taxation of natural resources planned for FY13 (not including workshops or short-term expert visits organized by FAD). - HQ-led TA missions are the foundation of staff work on EI fiscal regimes, supplemented by country visits, area department mission support, workshops, and conferences (e.g., Resources without Borders workshop, Washington, DC, May 2012). - The IMF published a major book on the topic in 2010 (Daniel, Keen, and McPherson). *Source: IMF staff text from the supplied content unit.* ### Appendix Figure 1. TA on Natural Resources Taxation by Sector, FY06–12 ### _081512 - Appendix Figure 1. TA on Natural Resources Taxation by Sector, FY06–12 ### IMF Technical Assistance (TA) Focus and Activities FY06–12 - TA concentrated mainly on taxation of petroleum (oil and gas) and mining (most commonly gold, copper, iron ore, and coal, but also uranium and diamonds). - Other resource topics occasionally addressed: hydropower and geothermal energy (Iceland 2011); forestry and commercial agriculture (Liberia 2009). - Recent TA innovation: advising on fiscal regime design for shale gas development (Poland 2012). - Most TA activities devoted solely to taxation of natural resources; in other cases, resource taxation was part of broader tax policy reviews (Malawi 2011; Tanzania 2012) or linked to fiscal decentralization (Peru 2006; Liberia 2009; Bolivia 2010). - FARI (Fiscal Analysis of Resource Industries) modeling framework used to advise on macro-fiscal issues and resource revenue management; examples of FARI usage include Uganda 2008; Ghana and Nigeria 2010; Timor-Leste 2011; Sierra Leone 2012. - FARI embedded with four country teams in AFR; with FAD support, AFR is building staff capacity in this area. - Expansion of IMF work on revenue administration for resource-rich countries: projects launched in the Democratic Republic of Congo, Sierra Leone, Lao PDR, and Mongolia; Uganda and Zambia have also received advice. ### Observations on TA Content and Delivery - TA covered both sector-specific tax policy and wider tax-administration/fiscal decentralization linkages. - Some activities were non-mission engagements (charting of numbers of missions and other activities by year referenced for FY06–12). - Source: IMF staff estimates. ### Key Corporate Income Tax (CIT) Issues for Extractive Industries (substantive findings and policy considerations) - Valuation of production for income: - Valuation principles for income tax may not always conform to those for royalties; consistency is administratively simpler but may not be possible because income tax valuation must usually reach “net gain” and permit deductions back to the same point as costs. - For bulk minerals (bauxite, rutile, iron ore) and natural gas, valuation is complex; reference prices may be proprietary (e.g., Platts for iron ore) and require adaptation for quality and transport cost differentials. - Where minerals are sold on contract and arm’s length pricing does not hold, government should have a right of contract approval and the revenue authority should be able to offer advance pricing agreements. - Interaction of CIT and production sharing: - Production sharing creates a two-stage calculation: contractor receipts in cost oil and profit oil are aggregated as gross income for CIT with regular CIT deductions applied, often leading to separate administration of production sharing and tax. - Some systems use “pay-on-behalf” where contractor’s CIT liability is settled from the state share of profit oil, stabilizing tax payment. - Allowable deductions: - Deductible costs should usually give rise to taxable income for the person paid; this principle implies, for example, that WHTs can be levied on interest or technical service payments made to nonresidents. - Rate of CIT and link to additional rent taxation: - Appropriate CIT rate linked to wider goals: (1) whether government intends to reduce the general rate over time; (2) whether government wishes to maintain a higher CIT rate for EI; (3) balance with other taxes (dividend WHT, additional rent taxation). - A common CIT rate across sectors is usually preferable; CIT is a tax attributable to doing business, while royalty and rent taxes are specific to resource extraction. - Additional rent taxation can make CIT rate less important, especially if the rent tax rate adjusts to changes in CIT. - Capital allowances and definitions of capital expenditure: - Tax depreciation allowances for EI often generous relative to book or economic depreciation; can reduce risk but delay government revenue. - Counting capital allowances from year of expenditure can cause unintended accumulation of losses; common practice is to start initial capital allowances in year of commencement of commercial production, with a partial year rule (e.g., if production starts after six months, provide half a year’s capital allowance). - Development capital expenditure on drilling, waste removal, overburden stripping, shaft sinking, etc., is often immediately expensed; IFRS provides a basis for determining expensing vs amortization. - Losses carried forward and ring-fencing: - EI sectors often have extended or unlimited loss carry forward periods; no case for denying deduction of properly incurred losses. - License-by-license ring fencing requires criteria; Norway and the UK permit consolidation within a sector-wide ring fence for offshore petroleum; developing countries concerned about revenue deferral may prefer license-by-license ring-fencing. - Deductibility of interest: - General thin capitalization rules should usually apply; if weak, special provisions may be needed, e.g., deny immediate deduction for interest payments that exceed a proportion of income (for instance, 50 percent plus interest earned), with a possible “safe harbor” at a debt equity ratio of, say, 1.5:1. - Include arm’s length equivalent criterion as part of transfer pricing rules or specify a margin over a benchmark international US$ interest rate. - Environmental reclamation and rehabilitation—fiscal treatment: - Special rules needed for abandonment and reclamation expenses; detailed rules for specification of plans and budgets are necessary (questions include whether to include projected inflation or discount future budgeted cost to present value). - Many countries have tax-deductible contributions to abandonment or reclamation funds. - Treatment of hedging: - Gains and losses on hedging can affect government revenues; governments should not be exposed to companies’ hedging operations except by positive choice. - Options: disregard hedging transactions and use reference prices; treat hedging under general CIT provisions; or, as in Australia, separate hedging into “commercial” and “financial” transactions. Staff tend to advise taxing on fair market value (benchmark price for spot market transactions) and excluding company hedging unless government chooses otherwise. - Gains on transfers of interest: - Policy questions: should gains be taxed? If gains reflect increase in expected future rents, taxing may be unnecessary where rent taxes are efficient (e.g., Norway). Other countries tax gains, often with complex rules (e.g., UK). Taxation tends to change timing of revenues and can increase the PV of government revenue. - Who can tax the gain? Problems arise when transfers involve share sales in chains of ownership beyond taxing jurisdiction. Example approach: South Africa “look through” provision where more than 80 percent of a company’s assets consist of mineral rights; transactions in its shares treated as transactions in the mineral right itself. Practical difficulties with treaty constraints and identifying non-resident transactions; enforcement tools include heavy penalties (forfeiture of mineral right if change of control not reported) or deemed gain provisions. - Care needed to avoid stifling exploration—junior companies rely on potential gains from farm-in or takeover as primary motive. - Fiscal terms for downstream processing: - Downstream processing (e.g., bauxite to alumina) may be treated as manufacturing/processing under normal CIT rules rather than mining tax; transfer-pricing rules needed to ensure resource taxation applies to upstream only. - For petroleum, parallel issues arise for processing and transportation of remote gas where transfer pricing must ensure upstream rent accrues at the appropriate stage. - Taxation of income by withholding: - WHTs can be important for early revenue and combating avoidance but must be carefully crafted. WHTs on payments to subcontractors may generate early revenue but can increase exploration and development costs since payments are commonly grossed up, increasing deductions against CIT and diluting revenue gain. - Clarity on WHTs is important to avoid friction, especially on payments to non-resident providers of services and on dividend and interest WHTs often reduced or eliminated in tax treaties. ### Appendix IV — What “Uplift” Rate should be used in Rent Taxes? (findings and practical guidance) - Theoretical benchmark: - If deferred tax benefits are certain to be ultimately received by the taxpayer (including, if necessary, as payments from the government), then carry forward of unrealized benefits at a risk-free rate is in principle appropriate (Fane, 1987; Bond and Devereux, 1995 and 2003). - Where there is doubt about government's commitment to provide benefits, risk-adjustment for that possibility is appropriate. Theory is silent on the appropriate rate when there is no risk-free rate; in many developing countries, there is not even a reliable long-term bond rate in local currency or in US$. If rates adjusted for activity risk are used, they can be argued to decline over time as project uncertainties diminish. - Practical country practices and outcomes: - Norway and the U.K. provide uplift broadly related to costs of capital, but are time-limited (4 and 5 years respectively) and so mimic a decrease over time. - Australian debates (2010): initial ACC proposal carried losses forward at the government bond rate; industry pressure led government to revert to risk-adjusted uplift. Australia also provides higher PRRT uplift for exploration expenditures than for development costs, making the uplift rate fall over time in effect. - Risk-adjusted uplifts pushed to very high levels (Ghana and Papua New Guinea) undermined credibility of the fiscal regime (since nothing was paid). Systems with risk-adjusted uplift have nonetheless collected significant revenue in Angola, Australia, Timor-Leste, and Zimbabwe. - Staff advice: - Staff generally advise developing countries to use low rates of uplift and to consider time-limiting them. ### Appendix V — Modeling the Impact of Fiscal Regimes on Resource Exploration and Exploitation (model structure and regimes analyzed) - Model structure (Smith (2012) central model): - Two-stage company decision framework: - Stage 1: optimal investment in exploration modeled as decision on maximum number of failures before abandoning a prospect; takes geological/technical discovery probabilities and fiscal regime as given; objective is to maximize expected NPV after taxes. - Stage 2: once a field is discovered, firm chooses primary and secondary recovery and abandonment timing; primary investment (continuous) fixes initial extraction rate; secondary investment (discrete timing) enhances remaining reserve; abandonment when marginal net revenue becomes negative. - Optimal investment choices obtained by maximizing after-tax NPV. - Calibration and analysis: - Model calibrated for a typical oil field using parameters based on actual investments. - Used to analyze impact of three stylized fiscal regimes: (1) royalty-only regime; (2) production sharing contract, either fixed or progressive; (3) resource rent tax, either fixed or progressive. - Extensions explored: price uncertainty impacts on investment delay; effect of ring-fencing on exploration decisions; framework provides qualitative characterization and quantitative indication of distortions induced by tax regimes. ### Appendix VI — FARI Appraisal of Different Rent Tax Mechanisms (objectives, indicators, and approach) - Objectives and measurable indicators (selected): - Maximize government revenue: Average Effective Tax Rate (share of pre tax NPV); Expected government revenue under price uncertainty. - Progressivity with price: Share of total benefits (= government NPV as a proportion of NPV of project positive cash flows, excluding initial investment): price sensitivity. - Progressivity with costs: Share of total benefits: cost sensitivity. - Avoid distortion of investment and operating decisions (neutrality): Marginal Effective Tax Rate (METR) (government proportion of pre-tax return for a project just viable post-tax); Breakeven commodity price; Probability of negative NPV under price uncertainty; Gold plating analysis. - Adequate incentive to invest: Post-tax internal rate of return to investor (IRR); Years until discounted payback achieved; Coefficient of variation of investor IRR and NPV; Probability of negative NPV with price uncertainty; Expected Monetary Value (EMV) (NPV weighted by exploration risk). - Manage government risk: Time profile of revenues; Proportion of total revenue received in first 5 years of production; Coefficient of variation of NPV of government revenues. - Minimize administrative burden and risks: Complexity; vulnerability to manipulation. - Approach used in FARI appraisal: - Define petroleum and gold mining project examples with stylized production and cost profiles consistent with actual projects. - Define a set of fiscal regimes, each comprising (1) an identical CIT with commonly encountered parameters; and (2) a single additional rent tax mechanism (in some cases different for petroleum and mining). - Calibrate each additional rent tax mechanism such that the AETR (NPV(10)) for all regimes is identical at around 70 percent for the petroleum regimes and 60 percent for the mining regimes, for project pre-tax rates of return of around 40 percent for oil and 30 percent for mining. These pre-tax returns represent relatively profitable projects, and the calibrated AETRs are within the range observed in actual petroleum and mining regimes. - Evaluate each rent tax mechanism’s application to different projects, including responsiveness to changes in project profitability by varying commodity prices and costs. - Petroleum analysis specifics: - Examines a “success” case, then includes exploration risk, and finally the risk of “gold plating.” *Source: IMF staff estimates (content extracted from Appendix Figures and accompanying appendices in PDF). * ### Appendix Table 2 sets out the mechanisms selected for ### _081512 - Appendix Table 2 sets out the mechanisms selected for ### Mechanisms selected for analysis (Appendix Table 2) - Parameter: Minimum marginal share 1/ — Maximum marginal share — Note (table of regimes). - Examples of regimes and their reported marginal shares: - Corporate Income tax only: Minimum marginal share 0% — Maximum marginal share 30%. - $1.925 Bn Signature bonus: Maximum marginal share 30%. - Full government participation (Brown Tax): Minimum marginal share 70% — Maximum marginal share 70%. - Carried participation: Minimum marginal share 0% — Maximum marginal share 50% (government share of cash contributions carried at 15 percent interest). - Flat royalty 35%: Minimum marginal share 35% — Maximum marginal share 58% (royalty deductible for CIT). - Flat 20% / Prog 25% Flat + price progressive royalty: Minimum marginal share 20% — Maximum marginal share 62% (price royalty triggered for oil price above $60; reaches maximum rate at $160). - Norway-style Special Petroleum Tax: Minimum marginal share 0% — Maximum marginal share 69% (30 percent uplift on capital expenditure over 4 years; immediate payout of tax-value of exploration costs and payout of unrecouped losses plus accumulated interest at end of project). - Australia-style Petroleum Resource Rent Tax (PRRT): Minimum marginal share 0% — Maximum marginal share 69% (PRRT on net cash flows after deduction of uplift on exploration (bond rate + 15 percent) and other expenditure (bond rate + 5 percent); PRRT deductible for CIT). - Cashflow surcharge without uplift: Minimum marginal share 0% — Maximum marginal share 70% (additional tax on same base as income tax, with interest charges added back; immediate write off of capital expenditure). - Production Sharing Contracts (selected): e.g., PSC: DROP sharing (13%–87%); PSC: ROR 5-tier (7%–74%); PSC: R-Factor (11%–69%); PSC: ROR Single tier (Pre-tax) (0%–69%). ### Deterministic / “Success case” economics (Appendix Figure 3) - Base case assumptions and project description used for comparison: - Oil price (base): $90 per barrel. - Field: Offshore 290 MMbl. - Size (project): 287 MMbl. - Costs: $23.0 bl (total project life). - IRR pre-tax: 39%. - Discount Rate: 10.0%. - Key deterministic findings: - All regimes have the same AETR for the base project at the base case oil price of $90 per barrel. - Regimes respond very differently to price and cost changes; royalty regimes respond hardly at all to price and cost variation. - Royalty regimes tend to distort project selection and limit the feasible range of projects relative to profit-sensitive regimes. - Hurdle price and METR charts indicate wide variation across regimes in the oil price required to reach the investor hurdle (example hurdle rate = 10%). ### Project examples and cost profiles (Appendix Table 3) - Project names and sizes (production): - Project name / Production MMBl: 100 MMbl — 104; 290 MMbl — 287; 880 MMbl — 883. - Production life (years): 100 MMbl — 13; 290 MMbl — 21; 880 MMbl — 22. - Project costs over project life ($mm) — Offshore 290 MMbl case (selected): - Exploration: 330 - Development costs: 2,500 - Sustaining capital: 1,125 - Operating costs: 2,387 - Decommissioning costs: 250 - Total: 6,592 - Per barrel ($Bl) — Offshore 290 MMbl: - Exploration: 1.1 - Development costs: 8.7 - Sustaining capital: 3.9 - Operating costs: 8.3 - Decommissioning costs: 0.9 - Total: 23.0 ### Taking oil price uncertainty into account (Appendix Table 4 and Appendix Figure 4) - Stochastic oil price analysis summary: - The deterministic expected pre-tax IRR of the success-case project is 39%; when oil price uncertainty (AR(1) process) is incorporated, the expected pre-tax IRR is now 31 percent. - With lower and volatile oil prices, revenue-based mechanisms (royalties, signature bonus) raise expected AETR and investor risk. - Comparative stochastic results (ranked by investor IRR; selected exact figures preserved where shown): - The expected pre-tax IRR of the stochastic project: 31 percent (text summary). - Signature bonus ($1.925Bn) results in the highest expected AETR and highest risk of loss to the investor because the bonus is paid irrespective of actual profitability. - Appendix Figure 4 shows that royalty and other revenue-based mechanisms yield: - Lower expected investor IRR and NPV (Columns 1 and 2 in Appendix Table 4). - Higher expected AETR (Column 3). - Longer discounted payback periods (Column 4). - Higher coefficient of variation of IRR (Column 5). - Higher probability of absolute loss (Column 6) — defined as the proportion of stochastic model runs in which the after-tax investor return is lower than an assumed 10 percent hurdle rate. - Example numeric highlights from Appendix Figure 4 (Offshore 290 MMbl; selected regimes and reported numbers): - Project before tax: Mean Investor post tax IRR 30.7 — Government NPV10: 3,630 — Expected AETR (percent) 11.7 — other columns: n/a - 70% Pure state participation (Brown Tax): Mean Investor post tax IRR 30.7 — Government NPV10: 1,089 — Expected AETR 70 — 11.7 — 46 — 168 — 2,541 (table formatting in source merges columns; preserved numbers as shown). - Base Regime: CIT only: Mean Investor post tax IRR 26.0 — Government NPV10: 2,403 — Expected AETR 34 — 12.1 — 48 — -1110 — 1,227 (preserved as presented). - Norway-Style Special Petroleum Tax: Mean Investor post tax IRR 20.8 — Government NPV10: 1,055 — Expected AETR 71 — 12.5 — 42 — 0 — 12? (preserved as presented despite merged formatting). - PSC: ROR Single tier (PreTax): Mean Investor post tax IRR 19.9 — Government NPV10: 1,033 — Expected AETR 72 — 12.3 — 44 — -1111 — 2,597. - Australia-style PRRT: Mean Investor post tax IRR 19.8 — Government NPV10: 1,032 — Expected AETR 72 — 12.4 — 44 — -1111 — 2,598. - PSC: ROR 5 Tier: Mean Investor post tax IRR 19.7 — Government NPV10: 968 — Expected AETR 73 — 12.4 — 44 — -2914 — 2,662. - PSC: DROP sharing: Mean Investor post tax IRR 17.8 — Government NPV10: 1,875 — Expected AETR 12.9 — 55 — -65 — 23 — 2,712. - 35% royalty: Mean Investor post tax IRR 15.7 — Government NPV10: 2,177 — Expected AETR 13.1 — 71 — -174 — 34 — 2,809. - $1.925Bn Signature.Bonus: Mean Investor post tax IRR 10.1 — Government NPV10: 7,887 — Expected AETR 14.4 — 64 — -586 — 50 — 3,152. - (Note: numeric columns in the source table are concatenated and presented without clear column separators; numbers above are preserved verbatim as they appear in the source table/relevant rows.) - Summary implication: - Revenue-based mechanisms raise investor downside risk under price uncertainty; signature bonus is especially punitive under volatility because of fixed upfront payment. ### Exploration risk and Expected Monetary Value (EMV) (Appendix Figure 5 and Appendix Box 1) - EMV definition and formula (Appendix Box 1): - EMV = p × NPVProject × (1-TaxRate) – (1-p) × NPCExplore × (1-TaxRefund) - where: - p ≡ probability of a commercially viable discovery (which averages 10–20 percent worldwide) - NPVProject ≡ expected pre-tax NPV conditional on commercial discovery - Tax Rate ≡ government share of project NPV - NPCExplore ≡ net present cost of exploration activity required before failure is reached - TaxRefund ≡ the refund of losses or tax deduction the investor receives in relation to the exploration cost - Key EMV findings (290 MMbl example; Appendix Figure 5): - All regimes appear viable when evaluated on success-case AETR alone: the success-case AETR (Appendix Table 4, Column 3) is less than 100 percent for all regimes. - Most regimes approach non-viability once exploration risk is considered: - The government share in the expected NPV with a 15 percent chance of success (government share of EMV) can exceed 100 percent, implying a negative EMV for the investor. - Fixed royalty and signature bonus regimes become unviable under a 15 percent chance of success: - Under fixed royalty, EMV is negative and exploration would not be undertaken. - Under signature bonus ($1.925 billion), no rational investor would pay that bonus given a 15 percent chance of success. - With a 15 percent chance of success the investor can pay a bonus of no more than $230 million if the EMV is to be positive (explicitly reported in source). - Regimes in which the government refunds or guarantees its share of exploration costs remain viable (e.g., Norwegian-style regime that pays out exploration costs approaches neutrality). - Policy-relevant numeric points: - Typical probability of commercial discovery p: 10–20 percent (source text). - Example used in EMV charts: 15 percent chance of success (used to illustrate viability thresholds). - Maximum signature bonus consistent with positive EMV at 15 percent chance of success: $230mm (source statement). ### Gold plating risk (definition, causes, and mitigation) - Definition: - ‘Gold plating’ is a situation in which the fiscal regime creates an incentive to spend more than is necessary, or bring forward investment; equivalently, the marginal effective tax rate associated with some expenditure is negative. - How gold plating arises: - Under standard CIT when tax rate is expected to fall (investment deductions taken at a higher tax rate than the future tax on additional profits). - Under Rent taxes using a notional rate or return (ROR) when the ROR threshold is materially higher than the investor’s discount rate and the tax rate is very high. - Multiple-tier ROR schemes are more likely to create a Gold Plating Incentive (GPI) because upper tiers often have accumulation rates much higher than investors’ discount rates. - Projects with longer, flatter production profiles are more vulnerable to GPI because uplift compounds over a longer period. - Mitigation and design guidance: - Careful choice of benchmark ROR is required to limit gold plating (see reference to Appendix IV in source). - Single-tier ROR schemes can provide sufficient flexibility and progressivity while reducing GPI risk relative to multiple-tier schemes. - Recognize that GPI is more likely to be exploited in relatively profitable projects; marginal projects face a trade-off and are less likely to be gold-plated. ### Policy conclusions and recommendations (preserving source judgments and terminology) - Fiscal regimes should account explicitly for oil price risk and exploration risk when setting government share, because: - Revenue-based mechanisms (royalties, signature bonuses) transfer price and downside risk to investors, raising expected AETR and probability of absolute loss under price uncertainty. - High fixed upfront charges (signature bonuses) can render exploration unviable under realistic success probabilities (example: $1.925 Bn bonus unviable at 15 percent success; $230mm is the maximum bonus consistent with positive EMV at 15 percent success). - To foster exploration and avoid deterring investment, governments can: - Refund failed exploration costs directly (as in Norway) or allow effective loss offsets; regimes that refund failures remain viable even with low discovery probabilities. - Provide or facilitate improved geological information (e.g., government-funded basic exploration or speculative seismic surveys) to reduce exploration risk and thus allow a higher government share of successful projects. - Configure fiscal terms cognizant of the government’s ability (or inability) to guarantee payouts of losses — if a government cannot credibly guarantee loss payouts it must set more investor-friendly terms. - Design fiscal rent instruments to limit gold plating: - Avoid excessive ROR thresholds above investors’ discount rates and avoid multi-tier accumulation rates that are materially higher than investor discount rates. - Consider single-tier ROR schemes to achieve progressivity without strong incentives to gold plate. *Italic: Source — Appendix material and figures/tables from the supplied IMF PDF content unit.* ### Appendix Table 5. Mining Fiscal Regimes Evaluated ### Appendix Table 5. Mining Fiscal Regimes Evaluated ### Summary of fiscal regime definitions and parameters - Working equity: participates in all negative and positive cashflows from commencement of project. (Footnote 1) - Resource Rent Tax (RRT): triggered when cashflow return reaches threshold. Pre-tax means cashflows exclude CIT, and RRT is deductible for CIT. (Footnote 2) - Windfall tax: government proportion of gold price above specified trigger. (Footnote 3) - Variable CIT rate: determined by ratio of taxable income to revenue. Tax rate % = 60 – 1150/(ratio*100) = max 48.5%. (Footnote 4) - Progressive royalty: gold price determines royalty on total production; non-incremental. (Footnote 5) - Resource Rent Tax (ACC): Allowance for Corporate Capital; uplift on undepreciated assets and losses. (Footnote 6) - ACC Henry Proposal: similar structure to Australia’s ACC Henry Proposal with modified parameters and zero royalty. (Footnote 7) - Australia-style MRRT: similar structure to Minerals RRT with modified parameters and zero royalty. (Footnote 8) ### Appendix Table 6. Gold Project Example ### Project statistics (GoldMine2MMOz) - Total production: 2 MM oz over 12 years - Unit costs (Project costs $MM $Oz): - Exploration: 50 | 25 - Capex: 348 | 174 - Opex: 789 | 395 - TC/RC: 115 | 58 - Decomm: 37 | 18 - Total: 1,339 | 670 - Pre-tax IRR at ConstReal $1300 Oz: 30% (also stated later as IRR pre tax: 29.6% and pre-tax IRR: 29.6% in figure captions) ### Assumptions common to regime evaluations - Project exports a gold concentrate requiring smelting outside the host country. (Footnote 1) - Corporate Income Tax (assumed for all regimes): Tax rate 10.0% (stated in one block) and Corporate Income Tax 30% (elsewhere as assumed CIT). Dividend withholding tax 10%. Assumed debt/equity 0%. - One-time uplift on development capital: 40.0% - Depreciation of development costs (yrs): 5 - Depreciation of replacement capital: 4 - Add-back interest: no - Losses paid out at end of life: yes (for many regimes; some regimes state "no") ### Selected regime calibrations and parameters (as presented) - Full government participation (Brown Tax) - Share of equity, from signature of license: 60% - Fixed Royalty - Royalty rate: 6% - Resource Rent Tax (cashflow basis) (RRT (Cflow)) - Resource rent tax: 16.0% - Return threshold: 12.5% - Basis: PreTax - Progressive Royalty - 6 tier Additional royalty min/max: 2.0% / 10.0% - Price band lowest / highest royalty: $1050 / $1450 - Price bands escalated: yes - Windfall Profits Tax - Free equity (share of dividends): 9.0% - Windfall tax rate: 16.0% - Resource Rent Tax (ACC) - RRT rate: 12% - Gold price trigger: $1,000 - Trigger escalated: no - Add-back interest: no - Uplift on undepreciated capital base: 12.5% - Variable Income Tax - Minimum income tax: 25% - Maximum income tax: 49% - Payout of losses at end of life: yes - ACC Henry proposal - RSPT rate: 14.0% - Uplift rate: 5.6% - Losses paid out at end of life: yes - Australia-style MRRT - RSPT rate: 16.0% - Uplift rate: 12.6% - Losses paid out at end of life: no ### Findings and comparative analysis (Appendix Figures and Tables) ### Deterministic price calibration results - All regimes (except Brown Tax) are calibrated to have approximately the same 60 percent share (AETR) at $1300 oz, and 30% pre-tax IRR at calibration. Brown Tax has the same share at all discount rates. - With deterministic prices, the progressive royalty appears not to add materially to risk. (Appendix Figure 6, bottom right) ### Stochastic gold price outcomes and implications - When using a stochastic gold price forecast (AR(1) process; Footnote 49), and prices are volatile and average lower than the $1,300 per ounce assumed for regime calibration: - The pre-tax IRR of the project is reduced to 18 percent, making it relatively marginal. - Appendix Table 7 / Appendix Figure 7 results with gold price uncertainty (GoldMine2MMOz): - Project before tax: - Mean Investor post tax IRR: 17.9 - Mean investor NPV10: 77.03 - Expected AETR: n/a - After tax (selected regimes; columns correspond to mean post-tax IRR, mean investor NPV10, Expected AETR (percent), Coefficient of variation of IRR, Probability of below target return of 10%, Government NPV10): - BrownTax: 17.9 | 64.36 | 0 | 77 | 32 | 96 - CIT_only: 14.3 | 75.85 | 38 | 14 | 18 | 5 - CIT+DWT_Only: 12.4 | 42.97 | 38 | 84 | 45 | 11 | 8 - Australia MRRT: 11.5 | 22.98 | 68 | 84 | 81 | 38 - RRT (ACC): 11.5 | 29.98 | 18 | 64 | 71 | 31 - VariableIncomeTax: 11.5 | 21.08 | 78 | 54 | 61 | 40 - RRT (Cflow): 11.4 | 21.58 | 78 | 84 | 81 | 39 - ProgressiveRoyalty: 11.2 | 21.78 | 68 | 74 | 81 | 39 - Special tax after uplift: 11.2 | 20.88 | 90 | 40 | 88 | 41 - ACC Henry proposal: 11.2 | 20.58 | 90 | 49 | 94 | 14 | 0 (tabular formatting in source is uneven) - WindfallTax: 11.1 | 20.28 | 89 | 48 | 94 | 81 | 41 - 9% Free Equity: 10.8 | 16.39 | 90 | 93 | 51 | 144 - Fixed Royalty: 10.6 | 9.49 | 49 | 75 | 31 | 51 - Note: the table in the source mixes columns and formatting; the above preserves numeric strings as provided. ### Key comparative findings - The fixed royalty adds materially to investor risk: - The expected AETR is around 94 percent for the fixed royalty in one reported column. - The fixed royalty regime is 20 percentage points more likely to result in a below-hurdle-rate return (Column 5 reference). - Progressive royalty and windfall regimes: - Imply higher risk to government because they are asymmetric—capturing only a share of price upside—and are more likely to be triggered with stochastic prices even though average price is lower. - Rate-of-return regimes: - Are lower risk for investors, without sacrificing much in terms of AETR and government NPV (Columns 3 and 6 referenced). ### Additional diagnostic observations (from Appendix Figure 6) - Profit-based regimes respond to cost changes, whereas royalty regimes do not. - Fixed royalty regimes do more to distort investment decisions and limit the feasible range of projects. - METR and hurdle price diagnostics presented: numerical METR rankings in figure indicate a spread with METR values noted in figure axes (exact figure numeric ticks preserved in source images). ### Appendix VII. Further Aspects of Effective EI Tax Administration ### Organizational and procedural principles - Integration of administration within a functionally-based structure is recommended. (Footnote 50) - Procedural best practice includes: - Clear rules of application consistent with the rest of the tax system, ideally set out in a tax procedure code (TPC). (Footnote 51) - Separation of duties to safeguard integrity. - Efficient routine processing with filing based on self-assessment. - Active enforcement of registration and payment. - Selective, risk-based audit. - Effective, accessible dispute resolution. - Comprehensive taxpayer service programs to foster voluntary compliance. - Capacity needs: - Good analytical, audit, and legal skills supplemented by specialist EI skills. - Since most EI tax is usually paid by a few companies, only a small number of professional staff is required. (Footnote 52) - In fragile or post-conflict contexts, outside expertise may need to be bought in, particularly for audit and mineral valuation. ### Governance and coordination issues - NEICs (national extractive industry companies) often retain inappropriate fiscal functions (equity, production sharing) that complicate administration. - NEICs should pay profit tax on equity participation like private companies, but tax compliance by NEICs is often poor; NEICs may not publish accounts per international accounting standards or be audited by international accountants. - Political and practical obstacles to reform: - Fiscal responsibilities may be embedded in legislation, contracts, international agreements, or constitutions. - Transferring fiscal responsibilities from NEICs and regulators to tax authorities may face resistance. ### Audit strategy and revenue protection - Effective revenue administration is focused on risk assessment: non-registration, non-filing, non-payment, or under-declaration are key risk sources. - Risk assessment should identify potential errors, estimate value and probability, estimate person-hours for audit, and allocate auditors to cases with highest expected return per auditor hour. - Short-term strategies for quick returns: - Better collaboration among agencies with revenue responsibilities. - Unified task force to audit the riskiest cases, concentrating on matters that can be investigated and settled quickly, possibly using outside expertise. - Special risks: - EI revenues are vulnerable to failure to audit during exploration and development phases, leading to inadequate knowledge of cost and asset bases when projects commence production. - Neglecting audits of exploration and development expenses can substantially erode the tax base as projects generate income. ### Appendix VIII. Revenue Data Used in this Paper ### Data collection and coverage - Annual data requested from IMF country teams on aggregate revenue from petroleum and mining sectors and composition by broad tax type for 2001–10. - Tax categories sought: royalty, license fees and bonuses, income tax, additional profits tax or similar, state equity, withholding on interest and dividends, profit oil, and indirect taxes (VAT and import and export duties). - Country selection intended to capture the universe of countries in which EI sectors are macroeconomically significant. ### Data availability and quality - Usable data were available for 57 countries (Appendix Table 8 lists them). - Complete aggregate EI revenue data are available on average for only 43 countries out of 67 that responded to the survey. - In many cases, breakdown by type of tax was not available. - Data may lack consistency in aggregation; some tax sub-categories were omitted due to poor reporting or level of disaggregation. Revenue in such cases might be slightly underestimated. ### Countries in the sample (as listed in Appendix Table 8) - Mineral Producers (selected entries): 1 Australia, 2 Bolivia, 3 Botswana, 4 Brazil, 5 Canada, 6 Chile, 7 Colombia, 8 Congo DRC, 9 Ghana, 10 Guinea, 11 Indonesia, 12 Kyrgyz Republic, 13 Lesotho, 14 Mauritania, 15 Mongolia, 16 Papua New Guinea, 17 Russian Federation, 18 Sierra Leone, 19 Tanzania, 20 Vietnam, 21 Zambia, 24 Malaysia, etc. - Petroleum Producers (selected entries): 1 Algeria, 2 Angola, 3 Australia, 4 Azerbaijan, 5 Bahrain, 6 Bolivia, 7 Brazil, 8 Brunei, 9 Cameroon, 10 Canada, 11 Chad, 12 Colombia, 13 Congo Republic, 14 Congo DRC, 15 Ecuador, 16 Equatorial Guinea, 17 Indonesia, 18 Iran, 19 Iraq, 20 Ivory Coast, 21 Kazakhstan, 22 Kuwait, 23 Libya, 24 Malaysia, 25 Mauritania, 26 Mexico, 27 Myanmar, 28 Namibia, 29 Niger, 30 Nigeria, 31 Norway, 32 Oman, 33 Papua New Guinea, 34 Philippines, 35 Qatar, 36 Russian Federation, 37 Saudi Arabia, 38 Sudan, 39 Syria, 40 Timor-Leste, 41 Trinidad and Tobago, 42 United Arab Emirates, 43 United Kingdom, 44 Uzbekistan, 45 Venezuela, Rep. Bol., 46 Vietnam, 47 Yemen. - Mineral and Petroleum Producers for which revenue data could not be broken down by sector (selected entries): 1 Australia, 2 Bolivia, 3 Brazil, 4 Canada, 5 Colombia, 6 Congo DRC, 7 Indonesia, 8 Mauritania, 9 Papua New Guinea, 10 Russian Federation, 11 Vietnam. *Source: IMF staff assumptions and compilation from Appendices V–VIII of the referenced paper.* ### Appendix IX. Improving Data on Government Revenues from Natural Resources ### Appendix IX. Improving Data on Government Revenues from Natural Resources ### IMF initiative and pilot approach - The Statistics department at the IMF is initiating work to ascertain the feasibility of collecting resource revenue data systematically in future. - Data would be compatible with Government Finance Statistics Manual 2001 (GFSM 2001) format, with comprehensive detail such as level of government and type of revenue (royalty, income tax, additional profit tax or other mechanism to capture rents, withholding on interest and dividends, indirect production taxes, etc.). - The work will begin with pilot studies: a selected group of three to four countries will be visited by Fund missions to investigate availability of information and produce a template for data collection. - Intention: countries to provide in the template whatever existing national data are available (regardless of its definition), and to identify the entities and level of government the data cover. ### Methodological and practical difficulties identified - No formal or internationally agreed definition of revenues from natural resources; national definitions limit cross-country comparability. - Need to define items included in resource revenues and identify the entities making payments to government; definition could be narrow or broad depending on the collection purpose. - Quality and reliability of available data are uncertain; many data are subsets of more aggregate government operation statistics and must be consistent with aggregate government revenue data. - GFSM 2001 framework should guide collection and enable linking national categories to GFSM classifications. - Level of government (central government vs non-financial public sector) materially affects figures; presence of large national companies in resource sectors alters coverage depending on level chosen. - Data may reside in entities not usually contacted by the IMF Statistics Department (e.g., Ministry of Natural Resources, trade organizations), requiring new contacts and familiarity with different formats. - Confidentiality and legal restrictions may prohibit disclosure of revenues collected from entities exploiting natural resources. *Source: Contributed by the Statistics Department.* --- ### Appendix X. Estimating Effective Tax Rates for EI Companies ### Objective and methods overview - The appendix examines how earnings from extractive industries (EIs) are shared between host government and private investor. - Two methods are applied: - Simulation methods to calculate Average Effective Tax Rates (AETRs) on particular projects (FARI model). - Use of accounting data to estimate Incremental Effective Tax Rates (IETRs) on additional earnings. ### Simulation methods (FARI model) - FARI model calculates pre- and post-tax flows from a specific project under assumptions on time paths of prices and extraction. - Strengths: precise identification of rent sharing for a specific project when exploration phase is included. - Weaknesses: departs from reality by assuming perfect implementation, abstracting from international tax planning and taxes in investors’ home countries or at shareholder level; requires assumptions on price and cost distributions that may differ from market perceptions. - FARI simulations point to AETRs in the range of 65–85 percent for petroleum and 40–60 percent in mining. ### Accounting-based IETR methodology - Using annual company accounts and SEC filings: compare changes in tax payments to increases in operating income beyond that presumed necessary to maintain a benchmark net return (benchmark taken in a base year and industry costs proxied by producer price index). - This yields an Incremental Effective Tax Rate (IETR): how tax payments vary with realized operating income, not an average effective rate at a date. ### Mining — illustrative IETR findings (Appendix Table 9) - Underlying procedure: operating income and producer prices normalized to 100 in 2004; adjusted operating income constructed; incremental earnings computed as actual less adjusted; additional tax payments compared to incremental earnings to derive IETR. - Implied IETR effective rates are in the order of 35–45 percent, and quite stable—except for a striking peak in 2009 driven largely by a fall in prices and production and a simultaneous surge in taxable non-operating income for a subset of companies. - Interpretation: fiscal regimes for mining appear not very progressive. Key reported figures from Appendix Table 9 (selected rows and results preserved exactly as in source): - A. Operating income index (Annual reports): 2004=100, 2005=175, 2006=295.1, 2007=381.8, 2008=418.6, 2009=236.3, 2010=515.2 - B. Producer price index: 2004=100, 2005=116.3, 2006=136, 2007=145.3, 2008=166.3, 2009=172.1, 2010=187.2 - E. Total tax (Annual reports): 2004=4481, 2005=8280, 2006=13904, 2007=18114, 2008=20179, 2009=14969, 2010=26900 - G. Tax on additional earnings (IETR): 2005=46.3%, 2006=37.2%, 2007=35.7%, 2008=36.9%, 2009=90.1%, 2010=40.2% ### Petroleum — illustrative IETR findings (Appendix Table 10) - Directly analogous methodology cannot be used for petroleum because financial statements do not provide payments to government under PSAs; instead infer pre-tax earnings assuming costs per barrel rise with sector producer prices. - Sample: accounting data for 27 large oil and gas producing companies (about 75 percent of the proven reserves of the world’s 50 largest oil companies, excluding national oil companies of OPEC countries). Incremental returns assessed relative to 2001. - Estimated IETRs for petroleum are in the range 45–65 percent. - Comparison with mining: petroleum fiscal regimes involve a higher incremental government take and tend to be more progressive (IETR increases sharply with price-driven earnings in petroleum; mining IETR varies little with initial earnings). Selected numeric rows from Appendix Table 10 (preserved exactly): - A. Oil prices (Brent crude, US$ per barrel): 2004=38.3, 2005=54.6, 2006=65.2, 2007=72.4, 2008=96.9, 2009=61.7, 2010=79.6 - B. Post-tax operating income (US$ million): 2004=186,608, 2005=250,690, 2006=301,590, 2007=319,265, 2008=419,229, 2009=298,562, 2010=361,003 - C. Oil & gas production (million boe): 2004=13,343, 2005=13,750, 2006=14,306, 2007=14,120, 2008=13,946, 2009=14,050, 2010=14,490 - D. Post-tax op. income per barrel (US$): 2004=14.0, 2005=18.2, 2006=21.1, 2007=22.6, 2008=30.1, 2009=21.3, 2010=24.9 - E. PPI Oil and Gas Extraction (2004=100): 2004=100.0, 2005=136.0, 2006=131.0, 2007=138.6, 2008=180.3, 2009=97.2, 2010=124.8 - G. Incremental post-tax operating income (US$): 2004=0.0, 2005=4.2, 2006=7.1, 2007=8.6, 2008=16.1, 2009=7.3, 2010=10.9 - I. Incremental pre-tax income, per barrel (US$): 2004=0.0, 2005=7.6, 2006=19.4, 2007=24.8, 2008=39.2, 2009=24.2, 2010=35.3 - J. Implied tax on incremental earnings, per barrel (US$): 2004=0, 2005=3, 2006=12, 2007=16, 2008=23, 2009=17, 2010=24 - K. Incremental effective tax rate = J/I: 2004=0%, 2005=44%, 2006=63%, 2007=65%, 2008=59%, 2009=70%, 2010=69% ### Projections and AETR distribution from company reserve disclosures - Companies filing under US GAAP and engaged in upstream oil and gas production must report future cash flows from their proven reserves using standardized assumptions on future oil and gas prices and separately identify future worldwide income tax expenses. - Ratio of undiscounted future income tax charges to undiscounted pre-tax net cash flows yields an estimate of (undiscounted) AETR. - Sample: distribution of undiscounted AETRs for a sample of 105 companies in 2005–10 (559 company-year observations). These companies account for about 85 percent of the proven reserves of the world’s 50 largest oil companies (excluding national oil companies of OPEC countries). - Over the full period, mean and median undiscounted AETR are 29 percent. - Substantial variation over time and across companies: highest AETRs commonly 85–90 percent and the lowest close to zero. ### Interpretative cautions and limitations - Reported undiscounted AETRs may underestimate effective tax rates for three reasons: 1. Cash flows reported are after payment of profit oil under PSAs or royalties and bonuses; such payments are omitted from reported tax obligations. 2. Mandated price expectations used in disclosures may be more conservative than investors’ expectations, and regimes may be progressive in prices. 3. Undiscounted AETR may not accurately capture AETR with a reasonable discount rate because tax payments tend to be back-loaded relative to earnings (investment credits and similar). For early-life projects, present-value AETR will be lower; for mature projects discounting has smaller impact. - On balance, the figures in Appendix Figure 8 should be regarded as a lower bound on AETRs faced in the petroleum sector. *Source: IMF staff calculations; Contributed by the Statistics Department.* ### References ### _081512 - References ### Theoretical perspectives and tax design - Boadway, Robin, and Michael Keen, 2010, “Theoretical Perspectives on Resource Tax Design,” in The Taxation of Petroleum and Minerals: Principles, Problems and Practice,” by Daniel, Keen, and McPherson (eds.), pp. 13–74. - Bond, Stephen R., and Michael P. Devereux, 1995, “On the design of a neutral business tax under uncertainty,” Journal of Public Economics 58, pp. 57–71. - _____, 2003, “Generalised R-based and S-based Taxes under Uncertainty,” Journal of Public Economics 87, pp. 1291–311. - Fane, G., 1987, “Neutral Taxation of under Uncertainty,” Journal of Public Economics, Vol. 31, pp. 95–105. - Garnaut, Ross, and Anthony Clunies Ross, 1975, “Uncertainty, Risk Aversion, and the Taxing of Natural Resource Projects,” Economic Journal, 85, 338, June, pp. 272–87. - _____, 1983, Taxation of Mineral Rents (Clarendon Press: Oxford [reissued 2011]. - Land, Bryan, 2010, “Resource Rent Taxation—Theory and Experience,” in Daniel, Keen, and McPherson (eds), op. cit. - Lund, Diderik, 2009, “Rent Taxation for Nonrenewable Resources,” Annual Review of Resource Economics, Annual Reviews, Vol. 1, pp. 287–308. - Krautkraemer, Jeffrey A., 1998, “Nonrenewable Resource Scarcity,” Journal of Economic Literature, Vol. 36, pp. 2065–107. - Calder, Jack, 2010a, “Resource Tax Administration: The Implications of Alternative Policy Choices,” in Daniel, Keen, and McPherson (eds.), op. cit., pp. 319–39. - Calder, Jack, 2010b, “Resource Tax Administration: Functions, Procedures and Institutions,” in Daniel, Keen, and McPherson (eds.), op. cit., pp. 340–77. ### Resource contracts, auctions, and state participation - Cramton, Peter, 2010, “How Best to Auction Natural Resources,” in Daniel, Keen, and McPherson, op. cit. pp. 289–316. - Daniel, Philip, 1995, “Evaluating State Participation in Mineral Projects: Equity, Infrastructure and Taxation,” in The Taxation of Mineral Enterprises by James Otto (ed.), Graham and : London, pp.165–87. - Daniel, Philip, and Emil Sunley, 2010, “Contractual Assurances of Fiscal Stability,” pp. 405–24 in Keen and McPherson (eds.), op. cit. - Daniel, Philip, Michael Keen, and Charles McPherson, 2010, The Taxation of Petroleum and Minerals: Principles, Problems and Practice, (Abingdon: Routledge). - Conrad, Robert, Bryce Hool, and Denis Nekipelov, 2009, “The Role of Royalties in Natural Resource Extraction Contracts,” Working Paper, Duke University. - Nellor, David C. and Marc S. 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Kumar, 2008, “Fiscal Rules, Fiscal Councils and All That: Commitment Devices, Signaling Tools or Smokescreens,” in Fiscal Policy: Current Issues and Challenges, proceedings of the 9th Banca d’Italia Workshop on Public Finance (Rome: Banca d’Italia). - International Monetary Fund, 2007, “Guide on Resource Revenue Transparency,” available at www.imf.org/external/np/pp/2007/eng/051507g.pdf - International Monetary Fund, 2010, “From Stimulus to Consolidation: Revenue and Expenditure Policies in Advanced and Emerging Economies,” available at www.imf.org/external/np/pp/eng/2010/043010a.pdf - International Monetary Fund, 2011, “Revenue Mobilization in Developing Countries,” available at www.imf.org/external/np/pp/eng/2011/030811.pdf ### Forecasting, commodity prices, and market analysis - Bowman, Chakriya, and Aasim Husain, 2004, “Forecasting Commodity Prices: Futures Versus Judgment,” IMF Working Paper 04/41, March (Washington: International Monetary Fund. - Reichsfeld, David A., and Shaun K. Roache, 2011, “ Do Commodity Futures Help Forecast Spot Prices?” IMF Working Paper 11/254 (Washington: International Monetary Fund). - Gelb, Alan, Kai Kaiser, and Lorena Viñuela, 2012, “How Much Does Natural Resource Extraction Really Diminish National Wealth? The Implications of Discovery,” Working Paper No. 290, Center for Global Development, July 9. - Eisenhauser, Joseph G., 2005, “A Test of Hotelling’s Valuation Principle for Nonrenewable Resources: Empirical Economic, Vol. 30, pp. 465–71. - Bowman, Chakriya, and Aasim Husain, 2004, “Forecasting Commodity Prices: Futures Versus Judgment,” IMF Working Paper 04/41, March (Washington: International Monetary Fund. - Mintz, Jack, and Duanjie Chen, 2012, “Capturing economic rents from resources: optimizing the structure of government revenues through royalties and taxes,” PWC Tax Policy Roundtable at the School of Public Policy, University of Calgary, February 29, 2012. - Reichsfeld, David A., and Shaun K. Roache, 2011, “ Do Commodity Futures Help Forecast Spot Prices?” IMF Working Paper 11/254 (Washington: International Monetary Fund). ### Empirical studies and case experience - Bornhorst, Fabian, Sanjeev Gupta, and John Thornton, 2009, “Natural Resource Endowments and the Domestic Revenue Effort,” European Journal of Political Economy, Vol. 25, pp. 439–46. - Rio Tinto, 2012, Taxes Paid in 2011, available at http://www.riotinto.com/ourapproach/taxespaidin2011.asp - Smith, James L., 2012, “Modeling the Impact of Petroleum Exploration and Development,” IMF Working Paper, forthcoming (Washington: International Monetary Fund). - Otto, James M. (ed),1995, The Taxation of Mineral Enterprises, Graham and London. - Otto, James, Craig Andrews, Fred Cawood, Michael Doggett, Pietro Guj, Frank Stermole, John Stermole, and John Tilton, 2006, Mining Royalties (Washington: World Bank). - Sims, Rod, 1985, “Government Ownership Versus Regulation of Mining Enterprises in Less-developed Countries,” Natural Resources Forum, 9, 4, (November), pp. 265–82. - Mullins, Peter, 2010, “International Tax Issues for the Resources Sector,” in Daniel, Keen, and McPherson (eds), op. cit. pp.378–402. - Osmundsen, Petter, 2010, “Time Consistency in Petroleum Taxation: Lessons from Norway,” in Daniel, Keen, and McPherson (eds), op. cit, pp. 425–44. - Reichsfeld, David A., and Shaun K. Roache, 2011, “ Do Commodity Futures Help Forecast Spot Prices?” IMF Working Paper 11/254 (Washington: International Monetary Fund). *Content from _081512 - References* --- _Source: https://www.imf.org/-/media/websites/imf/imported-full-text-pdf/external/np/pp/eng/2012/_081512.pdf_