CONSULTATION DRAFT National Fiscal Policy250217 · 2017. 3. 1. · 9.2 2016 Petroleum (Fiscal...

Nigeria National Petroleum Fiscal Policy – FINAL DRAFT

Ministry of Petroleum Resources 2

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THE GOVERNMENT OF

THE FEDERAL REPUBLIC OF NIGERIA

--------------------------------------------------------------------------------------------- NATIONAL PETROLEUM FISCAL POLICY

----------------------------------------------------------------------------------------------

The purpose of this document is to define the policy of the Federal Government of Nigeria in respect of Nigeria’s petroleum fiscal resources, establish short, medium and long-term targets for fiscal development and record strategies to be pursued to ensure the successful implementation of the Policy

FINAL DRAFT

20 September 2016



INDEX 1. EXECUTIVE SUMMARY .................................................................................. 152. SUMMARY ........................................................................................................ 20

2.1. Statement of the Petroleum Fiscal Policy .................................................. 202.2. Background of the Policy ........................................................................... 202.3. Aim and Objectives of the Policy ............................................................... 202.4. Vision, Purpose and Strategic Policy Objectives ....................................... 202.5. Background ................................................................................................ 212.6. Fiscal Rules of General Application ........................................................... 232.7. Fiscal Objectives and Fiscal Instruments ................................................... 242.8. Other Fiscal Instruments ............................................................................ 292.9. Costs and Prices ........................................................................................ 302.10Communications ........................................................................................ 312.11Roadmap and Action Plan .......................................................................... 31

3. OVERVIEW ....................................................................................................... 323.1. Statement of the Petroleum Fiscal Policy .................................................. 323.2. Background of the Policy ........................................................................... 323.3. Aim of the Policy ........................................................................................ 323.4. Objectives of the Policy .............................................................................. 32

4. VISION AND OBJECTIVES FOR PETROLEUM FISCAL REGIME ................ 334.1. Vision ......................................................................................................... 334.2. Purpose of the Petroleum Fiscal Policy ..................................................... 334.3. Strategic Policy Objectives ........................................................................ 33

5. INTRODUCTION AND BACKGROUND ........................................................... 345.1. Scope of the Policy and Definition of Petroleum ........................................ 345.2. Fiscal Basis for Reducing Poverty ............................................................. 355.3. Nigerian Petroleum Fiscal Setting .............................................................. 35

5.3.1. Three Types of Petroleum Arrangements ........................................... 355.3.2. Royalty Tax Fiscal System/ Concessionary Fiscal Regime ................ 375.3.3. Challenges with the Royalty / Tax System ......................................... 385.3.4. Production Sharing Contracts (PSCs) ................................................ 395.3.5. Gas Fiscal Terms ................................................................................ 41

5.4. Breakeven Oil Price for Nigeria .................................................................. 425.4.1. Forecast Prices ................................................................................... 425.4.2. IMF and Deutsche Bank Analysis ....................................................... 475.4.3. NNPC CP&S Analysis ......................................................................... 475.4.4. Government Take from a Barrel of Oil ................................................ 485.4.5. Analysis of Government Take ............................................................. 49

5.5. Fiscal Design for PIRB ............................................................................... 495.6. Examples of International Best Practice .................................................... 50

5.6.1. Fiscal Policies of Other Oil Producers ................................................ 505.6.2. Elements of Fiscal Policy to Offset Resource Dependency ................ 52

6. FISCAL RULES OF GENERAL APPLICATION .............................................. 556.1. Government Fiscal Philosophy .................................................................. 556.2. Introduction ................................................................................................ 566.3. Principles of the Fiscal Framework ............................................................ 576.4. Thematic Areas to be Addressed in a Fiscal System ................................ 58



7. FISCAL OBJECTIVES AND FISCAL INSTRUMENTS .................................... 597.1. Regressive and Progressive Fiscal Terms ................................................ 597.2. Capital Gains Tax ...................................................................................... 617.3. Fiscal Neutrality and Broad-Based Development ...................................... 627.4. Convergence and Divergence in Oil and Gas Prices ................................. 647.5. Early Dependable Revenue ....................................................................... 657.6. Limited Risk Exposure ............................................................................... 677.7. Review of PSC Terms ................................................................................ 687.8. Simplicity of Royalty and Tax Collection .................................................... 687.9. Transparency ............................................................................................. 697.10 Cost Curtailment and Improving Cost Efficiency ....................................... 73

8. OTHER FISCAL INSTRUMENTS ..................................................................... 738.1. Right Gas Pricing ....................................................................................... 738.2. Transitional Pricing Arrangements ............................................................. 74

8.2.1. Strategic Domestic Sector (Gas to Power) ......................................... 748.2.2. Strategic Industrial Sector/Gas Based Industries (GBI) ...................... 758.2.3. Flared Gas .......................................................................................... 768.2.4. Gas Pricing to Wholesalers/Local Distribution Companies ................. 768.2.5. Commercial Pricing for LNG/CNG ...................................................... 778.2.6. Gas Transportation Tariff .................................................................... 78

8.3. Incentives for Low Cost / Small Fields ....................................................... 788.4. Fiscal Incentives for LPG ........................................................................... 79

8.4.1. Gas Utilisation Incentives ................................................................... 798.4.2. LPG Pricing Policy .............................................................................. 798.4.3. Fiscal Incentives for LPG .................................................................... 798.4.4. Petroleum Products Pricing Policy ...................................................... 80

9. COSTS AND PRICES ....................................................................................... 829.2 2016 Petroleum (Fiscal Reform) Bill Terms ............................................... 82

9.2.1 Reliance on Royalty for Government Take Instead of Taxes ............. 839.2.2 Improved Fiscal Terms for Midstream Oil & Gas Investments............ 849.2.3 Removing the Deductibility of Acquisition Costs Under Qualifying Capital

Expenditure ......................................................................................... 849.2.4 Removing Gas Flare Penalties from Qualifying Deductions ............... 859.2.5 Requiring Economic Efficiency Tests for Regulations In Order To

Improve Regulatory Rule Setting ........................................................ 869.2.6 Avoiding Fiscal Incentives Abuse ....................................................... 869.2.7 Competitiveness of PIB 2016 Terms .................................................. 879.2.8 Cost Recovery Limit ............................................................................ 889.2.9 Government Take ............................................................................... 899.2.10 Investor Internal Rate of Return (IRR) ................................................ 89

9.3 COMPARISON OF FISCAL TERMS: CURRENT, 2014 PIB & PIRB 2016 909.3.1Tax Rates, Royalties .............................................................................. 909.3.2 Production Allowances ....................................................................... 91

9.3.3 Comparison of Royalty, NHT, Production Allowances between PIB 2014 and PIRB 2016 ............................................................................................................ 92

10 COMMUNICATIONS ......................................................................................... 98Introduction ........................................................................................................ 9810.1Internal Communications ........................................................................... 98

10.1.1Ministry ................................................................................................ 9810.1.2Other Government .............................................................................. 99



10.2External Communications ........................................................................ 10010.2.1Communication to Stakeholders ....................................................... 10010.2.2 Industry Involvement and Consultations ........................................... 100

11 ROADMAP AND ACTION PLAN ................................................................... 10111.1Summary of Philosophy ........................................................................... 10111.2Critical Policy Milestone ........................................................................... 10111.3Short-Term Activity (Up to One Year) – Enact Legislation ....................... 101



LIST OF FIGURES Figure 1. The Concept of Economic Rent. ............................................................... 26Figure 2. Laffer Curve .............................................................................................. 27Figure 3. Forms of Agreement – Fiscal Framework ................................................. 36Figure 4: Nigerian Fiscal Arrangements ................................................................... 36Figure 5: Percentage Government Take, Observed ................................................ 37Figure 6: Cost Control is Key to Maximising Government Take ............................... 38Figure 7: Nigerian Production Sharing Contract (PSC) Structure ............................ 39Figure 8: Growth in Deep Offshore Reserves following PSCs ................................. 40Figure 9: Low Royalty Rate in Nigerian 1993 PSCs ................................................. 40Figure 10: Oil Price Differential with $20/bbl (RT 1993) ........................................... 41Figure 11: Gas Specific Developments .................................................................... 41Figure 12: Global Crude Oil Price Movements, Real 2015 (1970-2015) .................. 43Figure 13: Global Crude Oil and Petroleum Liquids Inventory Change ................... 44Figure 14: Oil Prices and 5, 10, 15, 20, 25 Year Moving Averages, Nominal .......... 45Figure 15: Frequency Distribution of Oil Prices (1980-2015) ................................... 45Figure 16: Oil Price Outlook to 2035 ........................................................................ 46Figure 17: Nigerian Budget vs Break-Even Oil Price ............................................... 48Figure 18: Government Take under PSCs and JVs ................................................. 49Figure 19: Make Up of the Nigerian Economy ......................................................... 53Figure 20: Nigerian Oil Revenue vs Non-Oil Revenue (2010-2014) ........................ 54Figure 21: Gas Chain Diversification ........................................................................ 55Figure 22: Oil Chain Diversification .......................................................................... 55Figure 23: Rent Capture through Capital Gains Tax, African Countries .................. 61Figure 24: Gas Government Revenue Chain ........................................................... 63Figure 25: Crude and Natural Gas Prices, 1995-2015 ............................................. 65Figure 26: Royalty Rates by Oil Price ...................................................................... 66Figure 27: Investor Margins at Varying Oil Prices PPTA and PIRB ......................... 66Figure 28: Government Take as %age of Oil Price under PPTA and PIRB ............. 67Figure 29: Comparison of Government Take in some Deep Water PSCs, 2010 ..... 68Figure 30: Global Gas Price Movements (1998-2015) ............................................. 74Figure 31: Monthly Gas Price Movements at Major Pricing Points (2015-2016) ...... 74Figure 32. Relationship between Crude Oil price and Petroleum product price ....... 80Figure 33: Computation of Midstream pipeline Tariff. .............................................. 82Figure 34: Proposed Royalty Rates for Oil. .............................................................. 83Figure 35: Key Factors that Influence Foreign Investors. ......................................... 87Figure 36: Comparison of Cost Recovery Limit. ....................................................... 88Figure 37: Competitive Analysis of Comparison of Government Take and Investor

Rate of Return (IRR). ........................................................................................ 89Figure 38: Fiscal Regime Analysis of Investor PVR and IRR. ............................. 89Figure 39: Comparison: Oil Royalty by Production, Onshore ................................... 92Figure 40: Comparison: Oil Royalty by Production, Shallow .................................... 92Figure 41: Comparison: Oil Royalty by Production, Deepwater ............................... 93Figure 42: Comparison: Oil Royalty by Production, Price ........................................ 93Figure 43: Comparison: Gas Royalty, Onshore ....................................................... 94Figure 44: Comparison: Gas Royalty, Shallow ......................................................... 94Figure 45: Comparison: Gas Royalty, Deepwater .................................................... 95Figure 46: Comparison: NHT ................................................................................... 95Figure 47: Oil Royalty by Production ........................................................................ 96Figure 48: Gas Royalty ............................................................................................. 96Figure 49: Draft Fiscal Analysis Test Examples ....................................................... 97



LIST OF TABLES

Table 1: Fiscal Objectives ........................................................................................ 25Table 2: Five Year Moving Crude Oil Prices ............................................................ 44Table 3: Oil Producers Budget Break-Even Oil Price ............................................... 47Table 4: Government Take from Oil Revenue .......................................................... 48Table 5: Fiscal Regime for Selection of Oil Producing Nations ................................ 51Table 6: Features of Free Trade Zone Clusters ....................................................... 54Table 7: Regressive to Progressive Fiscal Terms .................................................... 59Table 8: Regressive to Progressive Fiscal Terms, Choosing the Right Mix ............. 60Table 9: Fiscal Transparency Principals .................................................................. 70Table 10: Table for Product Reference Price for Gas Based Industries .................. 76Table 11. Improved competition on Petroleum products pricing. ............................. 81Table 12: Fiscal Terms table. ................................................................................... 90Table 13: Tax and Royalty Rates under the Petroleum Fiscal Policy ...................... 90Table 14: Production Allowances under the Petroleum Fiscal Policy ...................... 91Table 15: Draft Fiscal Analysis Test Examples ........................................................ 97Table 16: Stakeholders comments on Key Fiscal Changes. .................................... 99



ABBREVIATIONS

AG Associated Gas AGFA Associated Gas Framework Agreement BoI Bank of Industry (Nigeria) Btoe Billion tons oil equivalent CapEx Capital Expenditure CBN Central Bank of Nigeria CDM Clean Development Mechanism CITA Company Income Tax Act CGT Capital Gains Tax CNG Compressed Natural Gas CPF Central Processing Facility C-P-R Cost Price Ratio DPR Department of Petroleum Resources DSO / DGSO Domestic Gas Supply Obligation EITI Extractive Industries Transparency Initiative EPP Export Parity Price, a netback gas price from export price FGN Federal Government of Nigeria FID Final Investment Decision FRGA Fiscal Rules of General Application GTLs Gas to Liquids IEA International Energy Agency, Paris IFC International Finance Corporation IFI International Financial Institution IMF International Monetary Fund IOC International Oil Company IPP Independent Power Producer JV Joint Venture iJV Incorporated Joint Venture uJV Unincorporated Joint Venture LNG Liquefied Natural Gas LPG Liquefied Petroleum Gas LRMC Long Run Marginal Cost MOU Memorandum of Understanding MPR Federal Ministry of Petroleum Resources MW / MWh Mega Watts / Mega Watt hours MYTO Multi-Year Tariff Order NAG Non-Associated Gas NAPIMS National Petroleum Investment Management Services NHT Nigerian Hydrocarbon Tax NLNG Nigeria Liquefied Natural Gas NNPC Nigerian National Petroleum Company



NOC National Oil and Gas Company NPDC Nigerian Petroleum Development Company Limited OGGS Offshore Gas Gathering System OML Oil Mining Licence OPEC Organisation of Petroleum Exporting Countries OPL Oil Prospecting Licence OSP Official Selling Price PIB Petroleum Industry Bill PIRB Petroleum Industry Reform Bill PA Petroleum Act 1969 PA Production Allowance PITA Petroleum Income Tax Act PPT Petroleum Profits Tax PPTA Petroleum Profits Tax Act PRG Partial Risk Guarantee PSC Production Sharing Contract R-factor Gross revenues divided by cumulative CapEx R&T Royalty and Taxes RE Renewable Energy RM Revenue Management ROR Rate of Return RRDE Resource Rich Developing Economy RSC Risk Service Contract scf standard cubic feet SI Savings Index SPDC Shell Petroleum Development Company SWF Strategic Wealth Fund US / USA United States of America VAT Value Added Tax WAGP West African Gas Pipeline WAGPA West African Gas Pipeline Authority WB World Bank



Units B / Bn billion bcf / bcf/d / bcf/a billion cubic feet / billion cubic feet per day / bcf per year bcm billion cubic metres bcma billion cubic metres per year bbl barrel GW Giga Watts kg kilogram m million M thousand MW / MW/h Mega Watts / Mega Watts hours MM million MMbtu million British thermal units MMscf million standard cubic feet MMscf/d million standard cubic feet per day Mscf thousand standard cubic feet mt million metric tonnes mtpa million metric tonnes per year scf standard cubic feet t metric tonne

Currencies N / NGN Naira £ Pounds Sterling € Euro $ / US$ / USD United States Dollar



NATIONAL PETROLEUM FISCAL POLICY 1. EXECUTIVE SUMMARY Statement of the Petroleum Fiscal Policy In this statement of the Petroleum Fiscal Policy, the Federal Government of Nigeria addresses the fiscal issues, articulates the vision for the sector and sets out appropriate fiscal policy goals and rules. It is intended that this policy will be reviewed and updated periodically to ensure consistency in Government policy objectives at all times. Once issued and gazetted, any policy position set out herein will bind Government officials unless and until amended or replaced by a formal restatement of policy duly gazetted by the Government. Vision, Purpose and Strategic Policy Objectives The vision of the National Petroleum Fiscal Policy is to have a fully developed fiscally sustainable, safe, secure, environmentally friendly, efficient and integrated petroleum operations for the socio-economic development of Nigeria. The purpose is to establish a fiscal framework that will guide the planning and development of petroleum activities in a rational and sustainable manner for the socio-economic development of Nigeria. The petroleum fiscal policy for Nigeria must address Nigeria’s energy trilemma of:

1. Addressing Energy Availability; 2. Enhancing Energy Accessibility; 3. Promoting Energy Affordability.

Definition: The National Petroleum Fiscal policy covers Upstream, Midstream and Downstream. Petroleum is defined to cover all petroleum related products, including crude oil, natural gas, LPG, and various gas liquids and condensates. The fiscal setting of the Nigerian Petroleum Industry is underpinned by three different types of petroleum arrangements, namely the:

• Royalty / Tax Fiscal Regime; • Production Sharing Contract (PSC) System; • Risk Service Contract (RSC) System.

There are several problems with the Royalty and the PSC arrangements (and RSCs are not common), such that a fiscal review has become imperative. Nigeria has to substantially reduce the costs of production. Analysis within the MPR and NNPC has derived a most likely average real future oil price to 2035, at $45/bbl. Nigeria has one of the highest cost of extraction amongst oil provinces in the world. The country additionally needs to diversify away from an economy based on



crude oil exports to one where the value added in processing oil streams is realised, combined with a move to a gas-based industrial economy. Fiscal Design for PIRB Under the legislation proposed for the petroleum sector, the new fiscal arrangements would seek to reduce the government take for the onshore and shallow water fields, where the burden is too high and is impeding development of smaller new fields, in particular for small companies. It will also aim to achieve the following:

1. Increase the government take in deep water, consistent with Section 16 of the Deep Offshore Act, comparable to international levels;

2. Make petroleum revenues easier to collect by improving the petroleum revenue governance framework;

3. Make the collection process more transparent through the petroleum revenue information system; and

4. Adjust the system to a modern international taxation framework. Overall Objectives of the Petroleum (Fiscal Reform) Bill:

1. All upstream petroleum operators should pay Company Income Tax; 2. A resource tax is introduced, the Nigerian Hydrocarbon Tax (NHT); 3. Eliminates Tax Offsets and Upstream Investment Tax Allowances; 4. Reduction of deductible items in assessing NHT; 5. Introduces volume and price based royalties.

Nigerian Hydrocarbon Tax (NHT, a simplified version of PPT):

• Applicable to all companies engaged in upstream petroleum operations; • Rates: 40% onshore, 30% shallow water and 20% deep water; • Production allowances limited by cumulative production and terrain and adjusted

such that the tax burden on gas projects are minimised; • Limited pool of Tax Deductible items; • Maximum of 80% recoverability of costs incurred overseas; • Same measurement point for royalty and taxes.

Volume and Price based Royalties:

• All production is subject to royalties based on monthly production; • Royalties in kind or cash with notice for gas royalties in kind; • 5% minimum royalty for oil and gas production depending on production rates; • 20% maximum royalty for production above 50,000 bpd, accounting for terrain; • 10% maximum royalty for production above 1000 mmscf, accounting for terrain; • 5% royalty for frontier areas for both oil and gas; • Sliding scale royalty rates not applicable to onshore and shallow offshore.

Royalty Based on Value, in Addition – Capturing Windfall Profits

• 0% royalty for crude oil price below $50/bbl; • A 0.2% increase for every $1 crude oil price increase above $50; • 20% maximum royalty rate for crude oil prices above $100; • No royalty by price for gas; • Threshold oil and gas prices indexed to account for inflation.



The new terms are comparable with international petroleum fiscal practice. Fiscal Rules of General Application: The purpose of the petroleum fiscal framework is that the state will be fiscally neutral as far as the types of hydrocarbons to be exploited. Fiscal Rules of General Application (FRGA) is the framework through which the interests of the state and that of the investor are codified. The petroleum fiscal policy framework is based around six key principles:

1. Right Pricing; 2. Sustainability; 3. Non-consolidation / Non-recovery of gas costs from oil income; 4. Separate Fiscal Treatment; 5. Upstream Incentives for Gas-For-Development; 6. Midstream Incentives.

Economic Rent: The Capital Gains Tax Act provides for a 10% rate on capital gains. The proposed new legislation would increase the capital gains tax in respect of asset-based transactions in the petroleum industry from 10% to 30%. Fiscal Neutrality and Broad-Based Development: Fiscal neutrality is enhanced, so that each segment of the value chain does not lean on the other. Similarly, the economics of gas across the value chain should not rely on cross - subsidies from oil. Gas capital and operating expense recoveries from oil as per AGFA will therefore no longer be available for all projects. As such, Sections 11 & 12 of the Petroleum Profit Tax Act (PPTA) as amended will be abrogated. Government Take Neutral: The Government take in the form of tax and royalty revenue will remain broadly the same after the new fiscal arrangements are introduced. The purpose is to design fiscal rules that enhance national development, not to increase government revenue directly. Limited Risk Exposure: By limiting the Government to post-exploration participation, the risk of upfront expenditure commitments by Government on exploration is minimised. Similarly, by basing Government Take principally on Royalties and less on Taxes, the Government eliminates “gold plating” costs and improves the Savings Index (SI). International Competitiveness and Balance of Objectives: The Deep Offshore Act provides for a review of 1993 PSC terms any time oil prices exceed $20/bbl real, so as to compensate the government from incremental revenues arising from higher oil prices. Since 2003, oil prices have exceeded $20/bbl without the government obtaining a fairer share of the incremental revenues. The Government now intends to put right this omission and will be reviewing PSC terms with operators. Royalty and tax collection is simplified through:

• Shifting collection towards rents and royalties and less on taxes; • Reducing the “tax nature” of Petroleum Profits Tax (PPT) by splitting it into:

o A Nigerian Hydrocarbon Tax (NHT) which will be easier to administer: § Because of fewer deductions; § And no capital uplift;



o Companies Income Tax (CIT), now to be paid by all petroleum companies; o Nigerian NHT not deductible for CIT purposes;

• Royalties, NHT, production sharing all on same production based revenues. Windfall profits are captured by:

• A new royalty scheme, in kind or cash, between 5% and 40%, based on: o Royalty scale based on daily production, ranging from 5% to 20%; o Royalty scale based on price, ranging from 0% to 20%; o No royalty based on gas price.

• A higher overall government take on profitable large fields under high prices, through royalties, Nigerian Hydrocarbon Tax and Companies Income Tax.

Transparency: Computationally simple tools are preferred, including Royalties, Production Bonuses, Linear Tax systems (proportionate tax methodologies) vs. non-linear such as R-factor or RoR based systems. As part of this simplification, the government intends to publish royalty templates under proposed regulations pursuant to the proposed fiscal law. Furthermore, consistent with the NEITI Act, a management information system which will cater for petroleum revenue information will be developed within the Ministry of Petroleum Resources. Cost Curtailment and Cost Efficiency: Cost recovery limits, production allowances rather than cost based incentives, lower taxes to improve the savings index and cost benchmarking are all market driven tools which enable industry wide cost efficiency. Right Gas Pricing: The gas pricing policy is now being integrated into gas fiscal terms so as to ensure the right pricing of gas and non-consolidation of gas expenditure with oil income. To this end, the gas pricing regulations of October 2008 are being reviewed and the provisions expanded to cover gas recovered from the flare, and gas produced and sold to LNG projects or other stranded gas to stranded industry projects. Transitional gas pricing arrangements will be in place until gas market liquidity has been achieved. The measures for determining that gas market liquidity has been achieved are set out in the National Gas Policy, a complementary policy to this Petroleum Fiscal Policy. Incentives for Low Cost / Small Fields: Low cost operations will be encouraged by creating more profits for efficient operators relative to inefficient operators, through:

• Placing more emphasis on royalties (where costs are not deducted); • The NHT streamlines tax collection by:

o Removing investment tax allowances and investment tax credits; o Removing deductibility of interest; o Increasing the amount of non-deductible costs; o Lowering the PPT rate in the form of Nigerian Hydrocarbon Tax rate; o Realigning the basis of tax payments to coincide with royalty payments,

thereby removing the current timing difference between them. The development of small fields will be encouraged by:

• A 5% royalty on small fields based on average daily production for the month;



• Significant production allowances under NHT which will reduce the tax rate to 0% for certain small field sizes. These allowances are particularly important in relation to small gas fields.

Fiscal Incentives for LPG and Mid-stream Gas Projects: LPG will be covered by the gas utilisation incentives intended for midstream projects as LPG appears as a result of midstream oil refining or gas processing. Consequently, in order to implement the Fiscal Rules of General Application, Section 39 of CITA will be amended to include LPG projects and LPG infrastructure. Fiscal Incentives for Refining and other Mid-stream Oil Projects: Under the new petroleum fiscal policy, mid-stream projects such as crude oil and product transportation systems and refineries will now benefit from similar terms obtainable under Section 39 of CITA. This is to ensure that processing of hydrocarbons and other extraction activities enjoy the same fiscal benefits and are kept distinct from the upstream. Costs and Prices: The fiscal design principles that underpin the Government’s fiscal policy is that the fiscal terms for extraction of hydrocarbons should be such that the cost of development to revenue (the Cost Price Ratio or C-P-R), should not exceed 30%. In other words, the fiscal system is designed to support cost efficient operations in order to reverse the six-fold increase in cost per barrel of production in Nigeria from 2004 to 2014. 2016 Fiscal Reform Legislation: Royalties, tax rates and production allowances under the Petroleum Fiscal Policy are set out in this Petroleum Fiscal Policy document. Communications: This petroleum fiscal policy therefore, while driven by and led by the government, is a joint production from the government and the petroleum industry community in Nigeria, with domestic and international industry involvement. Roadmap and Action Plan: Petroleum fiscal legislation is targeted to be enacted within one year.



2. SUMMARY

2.1. Statement of the Petroleum Fiscal Policy In this statement of the Petroleum Fiscal Policy, the Federal Government of Nigeria addresses the fiscal issues, articulates the vision for the sector and sets out appropriate fiscal policy goals and rules. It is intended that this policy will be reviewed and updated periodically to ensure consistency in Government policy objectives at all times. Once issued and gazetted, any policy position set out herein will bind Government officials unless and until amended or replaced by a formal restatement of policy duly gazetted by the Government.

2.2. Background of the Policy The fiscal framework for the exploitation of Nigeria’s oil and gas resources has been predicated on two key pieces of legislation:

• The Petroleum Act of 1969; and • The Petroleum Profits Tax Act of 1959.

2.3. Aim and Objectives of the Policy The aim of this document is to produce a National Petroleum Fiscal Policy that will serve the socio-economic needs of all stakeholders in the petroleum industry and provide for best practice governance in the fiscal management of revenues. This document seeks to:

1. Establish the context within which the National Petroleum Fiscal Policy is developed and implemented;

2. Set out the fiscal framework for a modern petroleum fiscal regime using fiscal rules of general application in Nigeria;

3. Describe the strategic approach that would be used to achieve the policy objectives.

2.4. Vision, Purpose and Strategic Policy Objectives The vision of the National Petroleum Fiscal Policy is to have fully developed fiscally sustainable, safe, secure, environmentally friendly, efficient and integrated petroleum operations for the socio-economic development of Nigeria. The purpose of the National Petroleum Fiscal Policy is to have established a fiscal framework that will guide the planning and development of petroleum activities in a rational and sustainable manner for the socio-economic development of Nigeria.



This policy is to be the basis for effective coordination among Government regulatory agencies with responsibility for petroleum matters, the collection of petroleum revenues and the harmonisation of national actions in relation to the petroleum resources of Nigeria. The petroleum fiscal policy for Nigeria must address Nigeria’s energy trilemma, of:

1. Addressing Energy Availability; 2. Enhancing Energy Accessibility; 3. Promoting Energy Affordability.

2.5. Background The scope of the National Petroleum Fiscal policy covers exploration, exploitation, production processing, transportation, distribution and marketing of petroleum (oil and gas) and its derivative products. These are sometimes referred to as Upstream, Midstream and Downstream petroleum operations. Petroleum is defined to cover all petroleum related products, including crude oil, natural gas, LPG and various gas liquids and condensates. The Nigerian Petroleum Fiscal policy delineates the fiscal incentives applicable to each business segment and provides a basis for increased private sector participation in the oil and gas industry. The fiscal setting of the Nigerian Petroleum Industry is underpinned by three different types of petroleum arrangements, namely the:


There are several problems with the royalty and the PSC arrangements (and RSCs are not common), such that a fiscal review has become imperative. Challenges include:

1. The high tax rate (85%) means that there is no incentive for cost reduction: 2. Government participation and cost risk without operational control: 3. Difficulty in efficient assessment and collection of tax; 4. Lack of integrated development planning to minimise cost; 5. AGFA terms that accentuate the decline in government take from oil; 6. Decline in government take with low oil prices, with no windfall profits; 7. Government inability to fund its equity in the JV operations. 8. Low royalty rates in PSCs.

Gas Fiscal terms: The fiscal setting for gas in the upstream has been dependent on oil and therefore the historical trend was that companies with upstream tax capacity tended to bring mid-stream projects for cost recovery under upstream terms. This often resulted in a reduced government take in oil projects and an entry barrier to investors who may lack upstream tax capacity. In other words, a discriminatory fiscal system arose out of gas incentives. This is an area that merits fiscal review.



Breakeven Oil Price for Nigeria Recent analysis within the MPR and NNPC has derived a most likely average real future oil price to 2035, at $45/bbl. The forecast oil price is substantially less than the oil price needed to sustain the Nigerian government budget. The 2016 government budget needs an oil price of $85/bbl. A $45/bbl is not enough even to fund the bare minimum government budget (recurrent expenditure + debt service).

The MPR long term crude oil price forecast is a range between $35-$55/bbl with a central case forecast of $45/bbl (forty five US Dollars) real.

Nigeria operates one of the highest cost-of-extraction among oil provinces in the world. The message is clear that Nigeria has to substantially reduce the costs of production if the country is to be competitive in the modern low oil price world, and if it is to have anything more than a bare minimum government take. Nigeria also imminently needs to diversify away from an economy based on crude oil exports to one where the value added in oil streams is realised, combined with a move to a gas based industrial economy. Fiscal Design for PIRB Under the legislation proposed for the petroleum sector, the new fiscal arrangements would seek to reduce the government take for the onshore and shallow water, where the burden is too high and is impeding development of smaller new fields, in particular for small companies. It will also aim to achieve the following:

1. Increase the government take in deep water, consistent with Section 16 of the Deep Offshore Act, comparable to international levels;


3. Make the collection process more transparent through the petroleum revenue information system;

4. Adjust the system to a modern international taxation framework. Overall Objectives of the Petroleum (Fiscal Reform) Bill:

1. All upstream petroleum operators should pay Company Income Tax; 2. A resource tax is introduced, the Nigerian Hydrocarbon Tax (NHT); 3. Eliminates Tax Offsets and Upstream Investment Tax Allowances; 4. Reduction of deductible items in assessing NHT; 5. Introduces volume and price based royalties.

Nigerian Hydrocarbon Tax (NHT, a simplified version of PPT)

• Applicable to all companies engaged in upstream petroleum operations;



• Rates: 40% onshore, 30% shallow water and 20% deep water ; • Production allowances limited by cumulative production and terrain and

adjusted such that the tax burden on gas projects are minimised ; • Limited pool of Tax Deductible items; • Maximum of 80% recoverability of costs incurred overseas; • Same measurement point for royalty and taxes.

Volume and Price based Royalties

• All production is subject to royalties based on monthly production; • Royalties in kind or cash with notice for gas royalties in kind; • 5% minimum royalty for oil and gas production depending on production rates • 20% maximum royalty for production above 50,000 bpd, accounting for terrain; • 10% maximum royalty for production above 1000 mmscf, accounting for terrain; • 5% royalty for frontier areas for both oil and gas; • Sliding scale royalty rates not applicable to onshore and shallow offshore.


• 0% royalty for crude oil price below $50/bbl; • A 0.2% increase for every $1 crude oil price increase above $50; • 25% maximum royalty rate for prices above $170; • Threshold oil and gas prices indexed to account for inflation.

The new terms are comparable with international petroleum fiscal practice. There are certain distinctive features of Resource Rich Developing Economies (RRDEs), including what has become known as the curse of oil. These negative features have characterised Nigeria in the past.

2.6. Fiscal Rules of General Application The philosophy for the fiscal framework of the gas policy is to set fiscal rules that are clear, transparent, globally competitive and designed to incentivise all participants. The role of the government is seen as not to create economic distortions that confers an advantage on or favour any particular party.

The purpose of the petroleum fiscal framework is that the state will be fiscally neutral as far as the types of hydrocarbons to be exploited. The policy therefore is to make gas economically viable to exploit, by reducing the state burden and to make gas standalone, separate from oil. Hence, gas projects will be developed based on their economics and not dependent on or consolidated against oil income.

Fiscal Rules of General Application (FRGA) is the framework through which the interests of the state and that of the investor are codified. This is best articulated with respect to Resource-Rich Developing Countries (RRDC). FRGA are based on clarity and transparency which require that:



• Rules are established by law and contracts are published; • Laws are consistent with the nation’s jurisprudence; • Laws and contracts minimise discretion; • Government revenue streams should occur during all production periods; • And should increase with a larger share of revenues as profitability increases; • Progressive fiscal systems that arise from FRGAs should be based on:

o Royalty (Early Revenues); o Regular Corporate Income Tax (CITA); o Tax on Rent (Hydrocarbon Tax).

• Resource tax can be made easier to administer. The fiscal policy must achieve competitive supply, balance the market, drive cost efficiency, and achieve competitive demand for sustainability. The role of the state is critical, the state must not compel commerce; rather it should regulate it. The state should interest itself in what is done, not who does it; and the state should not be involved in business risk activities. A fiscal policy on oil and gas must separately and distinctly provide for upstream, midstream and downstream. A “right pricing” (rather than high or low price) path is needed for petroleum, and market based tools are preferred over command and control mandates. The fiscal policy for gas must be one that enhances the economic value of gas through the right pricing of the commodity to reflect regional markets, and not through cross-subsidisation from oil. The petroleum fiscal policy framework is based around six key principles:

1. Right Pricing; 2. Sustainability; 3. Non-consolidation / Non-recovery of gas costs from oil income; 4. Separate Fiscal Treatment; 5. Upstream Incentives for Gas-For-Development; 6. Midstream Incentives.

Seven main thematic areas that must be addressed in the fiscal system are:

1. Governance; 2. Funding; 3. Fiscal incentives for investments; 4. Enabling gas exploitation; 5. The role of the regulator; 6. The role of the state in natural resource management; 7. Mitigating social consequences of natural resource exploitation.

2.7. Fiscal Objectives and Fiscal Instruments Modern fiscal systems try to be more progressive with a move towards tax-based incentives and taxes on profits. It is based around choosing the right mix of fiscal objectives and instruments to ensure a progressive petroleum fiscal regime.



Table 1: Fiscal Objectives

Fiscal Objective Preferred Instruments

Rent Capture / Progressivity

Progressive taxes or production shares, ideally rate of return-based. Service fees

Fiscal Neutrality / broad-based development

Profits-based taxes. No cross subsidy from oil to gas and vice-versa

Robustness / Adaptability Progressive taxes or production shares, ideally rate of return-based

Early, dependable revenue Royalties. Setting minimum percentage of profit oil, i.e., limiting annual share devoted to cost recovery

Limited risk exposure Royalties

International competitiveness / Balance of Objectives

Impact of overall mix of instruments is critical

Simplicity / Transparency Royalty. Taxes or shares linked to easily observed indicators/Fiscal Rules that are published

Cost Curtailment Cost Recovery Limits, Production Allowances instead of ITA, Lower Tax Rates

Economic Rent This is the difference between the payments received by a resource owner and the opportunity cost of the resource. In other words, payment received by a resource owner over and above the minimum needed to produce a good. Many resource owners are able to extract a portion of the economic profit generated by a business as economic rent. Optimizing economic rent to the owner (state) requires an optimization of the burden the state can impose on extraction activities. In the oil industry, this is the difference between the Gross value of the production and the cost of producing that resource (cost of supply) including an allowance for a normal rate of return on investment.



Figure 1. The Concept of Economic Rent.

Rent Capture: Revenues are generally the primary source of potential benefits to the host country such as Nigeria. Although this may not be exclusively the main objective of fiscal design, rent capture in a sustained and uninterrupted manner along with employment generation and lately environmental conservation are common priorities for host countries. It follows therefore that revenue maximizing rates (whether royalties/taxes) are often the fiscal tools used as long as they guarantee a fair and reasonable return for the investor.

Let tax revenue be: 𝑅 𝜏 = 𝜏 ∗ 𝑧 1 − 𝜏

Where:

𝜏 is Tax Rate

𝑧is Reported Tax Income (aka Tax base) and is a function of net-of-tax rate (1 − 𝜏) 𝑅 𝜏 , which is the Laffer Curve, has an inverse U – shape described by the following boundary conditions:

§ No Taxes : 𝜏 = 0 , 𝑅 𝜏 = 0

§ Confiscatory Taxes: 𝜏 = 1 , 𝑅 𝜏 = 0 § The Revenue Maximizing Rate be represented as 𝜏,-. then:

§ 𝜏,-. = //01

§ Where 𝜀 is the Elasticity of Tax Income to changes in net-of-tax rate.



§ It is inefficient to have Tax Rate in excess of the Revenue Maximizing Rate. i.e. 𝜏 > 𝜏,-.

§ Graphical representations of the Laffer curve appear to put 𝜏,-.at around 50%, however, the 𝜏,-.could lie anywhere between 0% and less than 100%

Figure 2. Laffer Curve

The essential feature of Nigerian Petroleum Fiscal Policy is optimising economic rent to the state because of the role of the state as a permanent sovereign over natural resources. The tools available to the state are essentially Royalty and Tax.

The Capital Gains Tax Act provides for a 10% rate on capital gains. The proposed new legislation would increase the Capital Gains Tax in respect of asset-based transactions in the petroleum industry from 10% to 30%.

Fiscal Neutrality and Broad-Based Development

Fiscal terms for Upstream, Midstream and Downstream are expected to stand on their own merit. Under the proposed new fiscal strategy, the requirement for fiscal neutrality is enhanced. Fiscal neutrality means each segment of the value chain does not lean on



the other, similarly the economics of gas across the value chain should not rely on cross subsidies from oil.

Gas capital and operating expense recoveries from oil as per AGFA will no longer be available for all projects; so Sections 11 & 12 of the Petroleum Profit Tax Act (PPTA) as amended stands abrogated.

Limited Risk Exposure By limiting the Government to post-exploration participation, the risk of upfront expenditure commitments by Government on exploration is minimised. Similarly, by basing Government Take principally on Royalties and less on Taxes, the Government eliminates “gold plating” costs and improves the Savings Index (SI). International Competitiveness and Balance of Objectives How costs are recovered and profits shared are at the heart of every fiscal system design. The fiscal system must provide a fair return to the state and to the industry. In other words, the objectives of both have to be balanced. They have to:

• Limit undue administrative burden and provide flexibility; • Enhance competitive demand and supply; • Improve market efficiency.

The Deep Offshore Act provides for a review of 1993 PSC terms any time oil prices exceed $20/bbl real, so as to compensate the government from incremental revenues arising from higher oil prices. Since 2003, oil prices have exceeded $20/bbl without the government obtaining a fairer share of the incremental revenues the government has been entitled to. The Government will now take steps to amend this situation and will seek to amend PSC terms with operators, consistent with the Deep Offshore Act. Royalty and tax collection is simplified through:

• Shifting collection towards rents and royalties and less on taxes; • Reducing the “tax nature” of Petroleum Profits Tax (PPT) by splitting it into:

o A Nigerian Hydrocarbon Tax which will be easier to administer; o Companies Income Tax, now to be paid by all petroleum companies; o Nigerian NHT not deductible for CIT purposes;

• Royalties, NHT, production sharing all on same production based revenues. Windfall profits are captured by:

• A new royalty scheme, in kind or cash, between 5% and 40%, based on: o Royalty scale based on daily production, ranging from 5% to 20%; o Royalty scale based on price, ranging from 0% to 20%; o No royalty based on gas price.



• A higher overall government take on profitable large fields under high prices, through royalties, Nigerian Hydrocarbon Tax and Companies Income Tax.

Transparency There is a wide variety of fiscal tools that can be used for the purposes of rent capture. However for Resource Rich Developing Economies (RRDE), computationally simple tools are preferred. Some of these tools include Royalties, Production Bonuses, Linear Tax systems (proportionate tax methodologies) vs. non-linear such as R-factor or RoR based systems. As part of this simplification, the government intends to publish royalty templates under proposed regulations pursuant to the proposed fiscal law. Furthermore, consistent with the NEITI Act, a management information system which will cater for petroleum revenue information will be developed within the Ministry of Petroleum Resources. Cost Curtailment and Improving Cost Efficiency Fiscal tools such as cost recovery limits, choice of production allowances rather than cost based incentives, lower taxes to improve the savings index and cost benchmarking (for the midstream for tariff setting) are all market driven tools which enable cost efficiency at the industry wide level.

2.8. Other Fiscal Instruments Right Gas Pricing The gas pricing policy is now being integrated into gas fiscal terms so as to ensure the right pricing of gas and non-consolidation of gas expenditure with oil income. To this end, the gas pricing regulations of October 2008 are being reviewed and the provisions expanded to cover gas recovered from the flare, and gas produced and sold to LNG projects or other stranded gas to stranded industry projects. Transitional gas pricing arrangements will be in place until gas market liquidity has been achieved. The measures for determining that gas market liquidity has been achieved are set out in the National Gas Policy, a complementary policy to this Petroleum Fiscal Policy. Incentives for Low Cost / Small Fields Low cost operations will be encouraged by creating more profits for efficient operators relative to inefficient operators. This will be achieved through:

• Placing more emphasis on royalties (where costs are not deducted); • The NHT streamlines tax collection by:

o Removing investment tax allowances and investment tax credits; o Removing deductibility of interest; o Increasing the amount of non-deductible costs; o Lowering the PPT rate in the form of Nigerian Hydrocarbon Tax rate; o Realigning the basis of tax payments to coincide with royalty payments,

thereby removing the current timing difference between them.



The development of small fields will be encouraged by:

• A 5% royalty on small fields based on average daily production for the month; • Significant production allowances under the Nigerian Hydrocarbon Tax (NHT)

which will reduce the tax rate to 0% for certain small field sizes. These allowances are particularly important in relation to small gas fields.

Fiscal Incentives for LPG and other Mid-stream Gas Projects Gas Utilisation Incentives: LPG as part of the gas value chain ought to be covered by the gas utilisation incentives intended for midstream projects as LPG appears as a result of midstream oil refining or gas processing. These include LNG, manufacturing of LPG cylinders as well as LPG related infrastructure. Consequently:

In order to implement fiscal rules of general application, Section 39 of CITA will be amended to include LPG projects and LPG infrastructure.

Fiscal Incentives for Refining and other Mid-stream Oil Projects Under the new petroleum fiscal policy, mid-stream projects such as crude oil, and product transportation systems and refineries will now benefit from similar terms obtainable under Section 39 of CITA. This is to ensure that processing of hydrocarbons and other extraction activities enjoy the same fiscal benefits and are kept distinct from the upstream.

2.9. Costs and Prices The fiscal design principles that underpin the Government’s fiscal policy is that the fiscal terms for extraction of hydrocarbons should be such that the cost of development to revenue (the Cost Price Ratio or C-P-R), should not exceed 30% of revenue.If not profit declines and in Net Present Value terms the project becomes uneconomic. With a cost-price ratio of 30%, the investor receives 17.5% of total revenues while the government take is 52.5% of total revenues. However, when the time value of money is computed, this can effectively limit the returns to single digits, which makes the investment a challenge. In other words, the fiscal system is designed to support cost efficient operations in order to reverse the six-fold increase in cost per barrel of production in Nigeria from 2004 to 2014.

Within this context, Nigeria’s fiscal regime is designed according to the simple rule that the C-P-R should not exceed 30%.

2016 Fiscal Reform Legislation The royalties, tax rates and production allowances under the Petroleum Fiscal Policy are set out in this Petroleum Fiscal Policy document, covering:

• Tax rates; • Production allowances.



2.10. Communications

Communications are important parts of any policy. There are two fundamental purposes for communication of the petroleum policy to all stakeholders in Nigeria and abroad:

1. Explaining the policy; 2. Changing attitudes.

A communications strategy will be developed as part of the Nigerian petroleum fiscal policy to explain to all stakeholders the purpose of the petroleum policy, and the thinking and analysis behind it.

The communications strategy will consist of two parts:

• Internal communications – audiences within government; • External communications – other stakeholders involved with the gas industry.

Industry Involvement and Consultations The petroleum industry in Nigeria has been involved in the development of the petroleum fiscal policy, through their participation in industry fora and seminars. This petroleum fiscal policy therefore, while driven by and led by the government, is a joint production from the government and the petroleum industry community in Nigeria, with domestic and international industry involvement.

2.11. Roadmap and Action Plan A roadmap and action plan for delivering the petroleum fiscal policy is set out with different scales for the types of activity:

• Short term: Months, up to one year; • Medium term: One to two years; • Long term: Over two years.

There is just one critical milestone for implementation of the petroleum fiscal policy, namely enactment of legislation. Enactment of petroleum fiscal legislation is targeted as a short term activity, that is, legislation is targeted to be enacted within one year.



3. OVERVIEW

3.1. Statement of the Petroleum Fiscal Policy In this statement of the Petroleum Fiscal Policy, the Federal Government of Nigeria addresses the fiscal issues, articulates the vision for the sector and sets out appropriate fiscal policy goals and rules. It is intended that this policy will be reviewed and updated periodically to ensure consistency in Government policy objectives at all times. Once issued and gazetted, any policy position set out herein will bind Government officials unless and until amended or replaced by a formal restatement of policy duly gazetted by the Government.

3.2. Background of the Policy Nigeria is a significant petroleum province holding reserves in excess of 36 billion barrels of oil, and 120 trillion cubic feet of gas, which ranks Nigeria as the 9th and 10th holder of reserves in the world respectively. The fiscal framework for the exploitation of the oil and gas has been predicated on two key pieces of legislation:

• The Petroleum Act of 1969; and • The Petroleum Profits Tax Act of 1959.

3.3. Aim of the Policy The aim of this document is to produce a National Petroleum Fiscal Policy that will serve the socio-economic needs of all stakeholders in the petroleum industry and provide for best practice governance in the fiscal management of petroleum revenues.

3.4. Objectives of the Policy This document seeks to:

1. Establish the context within which the National Petroleum Fiscal Policy is developed and implemented;

2. Set out the fiscal framework for a modern petroleum fiscal regime using fiscal rules of general application in Nigeria;

3. Describe the strategic approaches that would be used to achieve the policy objectives.



4. VISION AND OBJECTIVES FOR PETROLEUM FISCAL REGIME

4.1. Vision The vision of the National Petroleum Fiscal Policy is have a fully developed fiscally sustainable, safe, secure, environmentally friendly, efficient and integrated petroleum operations for the socio-economic development of Nigeria.

4.2. Purpose of the Petroleum Fiscal Policy The purpose of the National Petroleum Fiscal Policy is to have established a fiscal framework that will guide the planning and development of petroleum activities in a rational and sustainable manner for the socio-economic development of Nigeria. This policy is to be the basis for effective coordination among Government regulatory agencies with responsibility for petroleum matters and the harmonisation of national actions in relation to the petroleum resources of Nigeria.

4.3. Strategic Policy Objectives The petroleum fiscal policy for Nigeria must address Nigeria’s energy trilemma, of:

(i) Addressing Energy Availability: • Achieving competitive supply and balancing the market; • Incentivising value-adding investments in an enabled business

environment; • Fiscal neutrality among competing energy systems; • Focus on domestic supply as long as domestication does not involve

under pricing of either crude or products, which is what often creates economic distortion and encourages corruption.

(ii) Enhancing Energy Accessibility:

• Cost efficient infrastructure; • Open access regulation;

(iii) Promoting Energy Affordability:

• Energy equity, sustainability and reduction of energy poverty. Energy poverty refers to a situation where the well-being of large numbers of people in developing countries is negatively affected by:

a) Very low energy consumption; b) Use of dirty or polluting fuels; c) Excessive time spent collecting fuel to meet basic needs.



5. INTRODUCTION AND BACKGROUND

5.1. Scope of the Policy and Definition of Petroleum The scope of the National Petroleum Fiscal Policy covers exploration, exploitation, production processing, transportation, distribution and marketing of petroleum (oil and gas) and its derivative products. These are sometimes referred to as Upstream, Midstream and Downstream petroleum operations. Petroleum is defined to cover all petroleum related products, including crude oil, natural gas, LPG, and various gas liquids and condensates. For the Petroleum Policy, the parts of the petroleum value chain are defined as follows: Upstream: Activities related to:

• Exploration for, development and production of crude oil and gas; • Drilling and operation of oil and gas producing wells; • Construction and operation of crude oil flowlines and gas gathering pipelines; • Crude oil and gas separation and treatment facilities and operations; • Transportation of personnel and equipment to and from upstream petroleum

locations. Midstream: Activities related to:

• Construction and operation of crude oil and gas transportation pipelines after the flowstation;

• Oil refineries and gas processing facilities; • Oil and gas bulk storage facilities; • Shipping of oil and gas, and related products; • Other bulk transport methods, such as rail, barge and trucks for transporting

oil and gas, and related products, on a wholesale basis; • Wholesale marketing of petroleum products.

Downstream: Activities related to:

• Construction and operation of pipelines for distributing petroleum products and gas to retail customers;

• Retail stations for petroleum products; • City gate reception terminals for gas; • Distribution of petroleum and/or gas products; • Marketing, retailing and sale of petroleum products and/or gas.

The Nigerian Petroleum Fiscal policy delineates the fiscal incentives applicable to each business segment and provides a basis for increased private sector participation in the oil and gas industry.



5.2. Fiscal Basis for Reducing Poverty

The Nigerian Petroleum Fiscal Policy seeks to create a fiscal basis for the nation that will encourage investment and development of energy markets, plus regional integration to achieve a critical mass of consumer base and reduce poverty.

In addition to the issues of availability, accessibility and affordability, there is the issue of poverty and how a petroleum fiscal policy can reduce it. Measures to reduce poverty by achieving a critical mass of consumer base include:

• The strategic use of LPG as a domestic fuel and deregulation which encourage the efficient use of energy;

• A focus on expanding energy access which can be propelled by inexpensive energy supply plays, which can lead to large productivity gains, economic growth and poverty reduction;

• Emphasis on the role energy services can play as essential inputs to economic development and social progress, notably in achieving the Millennium Development Goals. In Nigeria under current economic conditions, provision of energy services is not attractive to market actors. Therefore, the major thrust of government fiscal policy must be to act vigorously to create conditions that allow for greater expanded access;

• The new fiscal policy stance is envisaged to provide solutions that encompass a critical mass for institutions and market aggregation, increasing reliability and maximising the benefit of local energy resources (coal in Enugu, gas in Delta, hydro in Mambila, Taraba, etc.), and the harmonisation of energy markets and frameworks;

• National energy policies which are underpinned by fiscal policies that take cognizance of the major benefits associated with regional energy integration (such as the West Africa Gas Pipeline or Trans-Sahara Gas Pipeline etc.). These include: improved security of supply, better economic efficiency, enhanced environmental quality and wider deployment of renewable energy resources.

5.3. Nigerian Petroleum Fiscal Setting

5.3.1. Three Types of Petroleum Arrangements The fiscal setting of the Nigerian Petroleum Industry is underpinned by three different types of petroleum arrangements, namely the:




Figure 3. Forms of Agreement – Fiscal Framework

Source: MPR Petroleum Fiscal Policy Team 2016 In Nigeria, four types of arrangement are in existence:

Figure 4: Nigerian Fiscal Arrangements Source: MPR Petroleum Fiscal Policy Team 2016 Note: JVs and PSCs contribute about 95% of Nigerian’s total oil & gas reserves and production There are two major fiscal arrangements in Nigeria that account for 95% of Nigerian’s total oil & gas reserves and production. They are:

Royalty/PPT System IOCs in JV with NNPC

Indigenous companies as concessionaire

Production Sharing Contracts

NNPC as Concessionaire, IOC as Contractor

Indigenous companies as concessionaire and IOC as contractor

Risk Service Contracts

NNPC/NPDC as concessionaire in RSC with AENR & SINOPEC

Sole Risk Concessions Indigenous companies as concessionaire



• Concessionary Arrangement (JV/Indigenous): Royalty/PPT System; and • Contractual Arrangement: Production Sharing Contracts (PSCs).

5.3.2. Royalty Tax Fiscal System/ Concessionary Fiscal Regime

1. The company bids for and is awarded rights to explore (OPL) and produce oil and gas (OML) for a specified period;

2. The Company operates subject to laws (Petroleum Act) and regulations of the state regulatory authority (DPR);

3. The company funds all exploration, development and operations expense to the extent of the working interest (equity in the license);

4. The government through NNPC holds 55-60% interest in JVs with IOCs; 5. If exploration is successful and production is initiated, the company pays

royalty, depreciates its assets and expenses its costs against revenue; 6. Company profits are taxed (PPTA); 7. Company receives a share of production (equity) and can book reserves.

The Royalty Tax System is still the predominant fiscal system in Nigeria. The system is based on concessionary awards of prospecting licenses and mining lease. It requires awardees to exercise their rights to be in petroleum operations. By virtue of the provisions of paragraph 35 of the Provisions of the Petroleum Act, the Federal Government began to acquire interests in the concessions previously awarded to International Oil Companies (IOCs). These interests were in the form of unincorporated Joint Ventures (uJVs). State participation through NNPC has meant that the government funds its share of exploration and production costs to the tune of 55-60% of undivided interests in the oil mining leases. As a result of the generally higher cost environment in Nigeria, government take has generally hovered around 50% or below as can be seen in the chart below. This contrasts with the generally even lower (less than half) of the government take in the Deep Offshore Production Sharing Contracts (PSCs).

Figure 5: Percentage Government Take, Observed

Source: MPR Petroleum Fiscal Policy Team 2016



5.3.3. Challenges with the Royalty / Tax System

Arising from this fiscal arrangement are several issues and challenges which have necessitated a review of the fiscal policy. These include:

1. The high tax rate (85%) means that there is no incentive for cost reduction: a. Nigeria has a low savings index;

2. Government participation without operational control:

a. Government bears about 94% of cost risk while the Company bears only 6% and has operational control;

3. Tax Administration:

a. Difficulty in efficient assessment and collection of tax; b. Difficulty in accessing cost data especially for the independents;

4. Lack of integrated development planning to minimise cost and maximise

government take;

5. Associated Gas Framework Agreement (AGFA) terms that accentuate the decline in government take from oil;

6. Decline in government take with low oil prices, with no provisions for windfall

profit;

7. Government inability to fund its equity in the JV operations. NOTE: Cost control is key to maximising government take.

Figure 6: Cost Control is Key to Maximising Government Take




5.3.4. Production Sharing Contracts (PSCs) • Company profits are taxed (PPTA);

• The company receives a share of production (equity) and can book reserves;

• IOC bids for and is awarded rights to explore (OPL) and produce oil and gas (OML) for a specified period as a contractor to the NOC which owns the OPLs and OMLs if IOC is successful;

• IOC funds all exploration, development and operations expense;

• In the PSC, assets are installed by the IOC but owned by the State;

• The PSC defines an order of allocation of proceeds between the parties: (1) Royalty Oil (2) Cost Oil (3) Tax Oil, (4) Profit Oil. Profit Oil is shared on a pre-determined split between IOC and NOC based on cumulative production;

• For risk sharing, the Contractor entity may be more than one IOC, in which case they would have signed a JOA to regulate their working relationship;

• If exploration is successful and production is initiated, IOC recovers costs. After cost recovery and tax oil is lifted, profit oil is shared among the parties (IOC and NOC);

• In Nigeria, IOC tax is paid on behalf of IOC by NOC through Tax Oil; • IOC receives a share of production (Cost Oil + Profit Oil) and can book

reserves. Figure 7: Nigerian Production Sharing Contract (PSC) Structure


Since 1975, Nigeria has operated a Production Sharing Contract (PSC) system, which was further enhanced in the form of the 1993 PSCs under the Deep Offshore Act. PSCs became the norm given the government’s funding constraints under the Joint



Venture Royalty Tax System. The choice of PSCs went beyond addressing funding constraints to include the following:

• High geological risk in deep water and inland basins ceded to IOCs; • Redirection of scarce resources; • Retention of title to concessions; • Drive to increase reserve base.

Following the granting of PSCs in the Deep Offshore, Nigeria’s crude oil reserves rapidly increased to 36 billion bbls and production from the Deep Offshore now averages about 548,000 bbls/day.

Figure 8: Growth in Deep Offshore Reserves following PSCs

Source: MPR Petroleum Fiscal Policy Team 2016 One of the key challenges of the 1993 PSCs is the low royalty rate and consequently the low government take. The chart below illustrates this anomaly where government take at an oil price about $30/bbl is almost zero.

Figure 9: Low Royalty Rate in Nigerian 1993 PSCs

Source: MPR Petroleum Fiscal Policy Team 2016 Correcting this anomaly in fiscal design is therefore a priority of fiscal policy review. Additionally, Section 16 of the Deep Offshore Act prescribes a change in government share of additional revenue when the price of oil exceeds $20/bbl (RT1993). This threshold has been met since 2003 as evident in the chart below.



Figure 10: Oil Price Differential with $20/bbl (RT 1993)

Source: MPR Petroleum Fiscal Policy Team 2016 Arising from the above and considering that notice of impending changes consistent with the Deep Offshore Act was issued in November 2008, the fiscal review of the PSCs has become imperative.

5.3.5. Gas Fiscal Terms Until recent years, gas fiscal terms have historically developed on the back of a series of projects and non-statutory pronouncements.

Figure 11: Gas Specific Developments

Source: MPR Petroleum Fiscal Policy Team 2016 However, two main laws, Section 11 & 12 of the PPT Act (Upstream Gas Terms) and Section 39 of CITA (Mid-stream Gas Terms), define the full range of fiscal incentives for gas in Nigeria. The PPT grants tax consolidation and cost recovery from oil taxes to developers of upstream gas projects for associated and non-associated gas while CITA grants tax holidays for mid-stream projects such as LNG and other gas utilisation projects.



The fiscal setting for gas in the upstream is dependent on oil and therefore the historical trend was that companies with upstream tax capacity tended to bring mid-stream projects for cost recovery under upstream terms. This often resulted in the lowering of government take in oil projects as earlier indicated and further unintended consequences from what has been in effect an entry barrier to investors who may lack upstream tax capacity. In other words, a discriminatory fiscal system arose out of gas incentives. This has led to a number of distortions:

1. It discriminates against non-oil tax capacity investors (that is, it discriminates against companies who do not have oil operations, and therefore are unable to expense their gas costs against oil operations in the manner that upstream investors in gas projects can);

2. It incentivises oil companies to build gas infrastructure (in some cases unnecessarily oversized gas infrastructure) for fiscal reasons (to include in their cost oil base and offset against their profit oil, which ultimately is paid for by the Nigerian government);

3. It has meant that the only gas infrastructure not built for fiscal purposes has been built by the Nigerian government, via NGC;

4. When the oil price is low (as is the situation now), tax capacity (the ability to collect tax on profit oil) declines.

This is an area that merits fiscal review. The fiscal focus of the review will be to accomplish the following:

• Fully exploit the potential in gas for accelerated economic development, in pursuit of the over 10% GDP growth aspiration;

• Concurrent focus on viable domestic, regional and other export markets;

• Competitively position Nigerian gas in terms of cost competitiveness and scalability of capacity;

• An integrated infrastructure strategy to support domestic, regional and export LNG markets;

• Attract new players into the Nigerian gas value chain; • Ensure commerciality for all investments.

5.4. Breakeven Oil Price for Nigeria Plunging oil prices have left many crude oil exporting countries with budget deficits. For most of the big oil exporting countries like Nigeria, oil accounts for the majority of the country’s exports and GDP. Falling oil prices have led to dramatic declines in government revenues.

5.4.1. Forecast Prices This section draws upon research and analysis which members of the Petroleum Policy Team in the MPR and NNPC carried out in 2016 on likely scenarios for crude



prices in the future. The analysis is based upon the concept that historic experience of oil price movements over time can give a good indication of future oil price behaviour. Historically, crude oil prices in the international market have reacted to a variety of geopolitical and economic events. The figure below highlights some key historic events that influence the prices of crude oil.

Figure 12: Global Crude Oil Price Movements, Real 2015 (1970-2015)

Source: BP Annual Statistical Review 2016; Analysis: MPR Petroleum Policy Team 2016 In an attempt to carry out a relatively realistic forecast on the future prices of oil therefore, the following factors, among others, must be considered:

• Changes in the expectations of economic growth; • Changes in global oil consumptions in relation to economic growth; • Changes in non-OPEC production; • Changes in non-OPEC supply expectations; • Changes in Saudi Arabia crude production; and • Growth in global inventory levels (see chart below).



Figure 13: Global Crude Oil and Petroleum Liquids Inventory Change

Source: EIA 2016; Analysis: MPR Petroleum Policy Team 2016 Taking these factors into consideration, coupled with the historical trends of price fluctuations, the study was carried out into likely scenarios for crude prices in the future. Looking at historical trends of crude oil prices, the moving average prices of crude for an interval of five years to 25 years were determined as tabulated below:

Table 2: Five Year Moving Crude Oil Prices Years Moving Price ($/bbl)

5 97.36 10 86.27 15 68.92 20 56.64 25 48.88

Source: MPR Petroleum Policy Team, NNPC CP&S From the moving average prices, a plot of the moving average prices against the historical prices since 1980 was obtained as shown below.



Figure 14: Oil Prices and 5, 10, 15, 20, 25 Year Moving Averages, Nominal

Source: MPR Petroleum Policy Team, NNPC CP&S The next chart shows the distribution of each range of oil prices and the relative frequency of each range of oil prices.

Figure 15: Frequency Distribution of Oil Prices (1980-2015)

Source: MPR Petroleum Policy Team, NNPC CP&S The above analysis shows that on most occasions, oil prices historically have been below $40/bbl, nominal. An analysis of the plot shows that oil prices exhibit log -normal distribution showing 67% of price frequencies being at most $37.45/bb (in other words, since 1980 the oil price has been below $40/bbl for more than two thirds of the time).

• $41.76/bbl is the mean average price since 1980;



• $57.25/bbl is the upper quartile price. Based on the earlier established trends and the frequency distribution of the prices of crude, a forecast to 2035 of real prices was developed with: $35/bbl minimum; $45/bbl most likely; $55/bbl maximum price. In line with the foregoing, the reality may be deduced that crude oil may never again reach the highs as was experienced in the period 2008-2014. This will become more so as renewable energy continues to gain market share rapidly. In conclusion, the most obvious and realistic line of action for any nation with oil as the backbone of its economy is to diversify, because indices point to the fact that the era of oil boom may be over for good.

The MPR long term crude oil price forecast is a range between $35-$55/bbl with a central case forecast of $45/bbl (forty five US Dollars) real.

Figure 16: Oil Price Outlook to 2035

Source: MPR Petroleum Policy Team, NNPC CP&S Note: Most likely price is $45/bbl real (2016) and is escalated each year from that in nominal terms



5.4.2. IMF and Deutsche Bank Analysis The International Monetary Fund (IMF) and Deutsche Bank have calculated the break-even oil price for the main oil producing nations around the world, that is, the oil price at which the country can balance its government budget. Deutsche Bank calculated that the government budget break-even oil price for Nigeria for the 2016 budget is $75.

Table 3: Oil Producers Budget Break-Even Oil Price Country

2016 Budget Break-Even Oil Price

2015 Budget Break-Even Oil Price

Libya $207.60 $184.10 Venezuela $111.30 $117.50 Bahrain $105.00 Oman $97.50 Saudi Arabia $95.80 $106.00 Algeria $93.00 $130.50 Russia $84.90 Nigeria $75.20 $122.70 Iraq $75.90 $100.60 Iran $70.40 $130.70 UAE $67.50 $77.30 Qatar $57.80 $60.00 Kuwait $51.80 $54.00

Sources: IMF (break-even price forecasts except for Russia, Nigeria and Venezuela); Deutsche Bank (break-even price forecasts for Russia, Nigeria and Venezuela) According to these estimates from the IMF and Deutsche Bank, Nigeria has very severely trimmed the national budget, from $122.70 in 2015 to $75.20 in 2016 (39% reduction) but even so, it is still far above the oil price for 2016 which is running in the range of $40-$50/bbl.

5.4.3. NNPC CP&S Analysis The data above is from analysis by the IMF and Deutsche Bank. Internal analyses within the Nigerian government (MPR Petroleum Policy Team and NNPC) have also considered the effect on Nigerian government budgets of the oil price. Analysis was made of the oil price necessary to fund four scenarios or cases for the government budget. The assumptions behind the analysis are:

• Average daily oil production is 2.2 mmbpd (2016 budget assumption); • Exchange rate is $1 = N197; • Government take from oil production is 50%; • 80% of the government budget is funded by government take on oil production.

The scenarios for government budget are:

• Case 1: 2016 Budget;



• Case 2: 2015 Budget; • Case 3: 2016 Budget minimum, just recurrent expenditure + debt service; • Case 4: 2016 Budget extreme, of 30% of recurrent expenditure + debt service.

The results of the analysis are shown in the following figure. They show that an oil price of $85/bbl is needed to fund the 2016 budget of N6.08tn. Even a stripped down bare minimum budget (basically paying government salaries and debt service, and nothing else) needs an oil price of $52/bbl, still above the prevailing oil price of 445/bbl. Only in Case 4 (where just 30% of government salaries are paid + debt service) is there a budget surplus.

Figure 17: Nigerian Budget vs Break-Even Oil Price

Source: NNPC CP&S The forecast of the Petroleum Policy Team is that the long-term real crude oil price will be $45/bbl. To break even therefore, the Nigerian government needs to trim the national budget by another 50%, which clearly, for any government, will be a very significant challenge.

5.4.4. Government Take from a Barrel of Oil The MPR has calculated that the Nigerian government takes around 50% of the revenue from a barrel of oil. If (say) the oil price were $100/bbl, estimated costs are $30, leaving a Divisible Income (gross profit) of $70. Royalties of 20% plus tax on net profit of 50% plus JV profit share lead to a total government take of around 50%.

Table 4: Government Take from Oil Revenue




5.4.5. Analysis of Government Take Figure 18: Government Take under PSCs and JVs

At current production costs in Nigeria, the graph shows what government take would be at a different oil prices. It shows that at an oil price of $45/bbl, government take (royalty and taxes), after costs and JV partner profit share, is in the range of $5-$10, which is far too low to meet even minimum government budgets.

Source: MPR Petroleum Fiscal Policy Team 2016 The message is clear that Nigeria has to substantially reduce the costs of production if the country is to be competitive in the modern low oil price world, and if it is to have anything more than a bare minimum government take. Nigeria also needs to diversify away from an economy based on crude oil exports to one where the value added in oil streams is realised, combined with a move to a gas based industrial economy.

5.5. Fiscal Design for PIRB Under the proposed Petroleum Industry Reform Bill (PIRB), the new fiscal arrangements would seek to reduce the government take for the onshore and shallow water, where the burden is too high and is impeding development of new fields, in particular by small companies. It will also aim to achieve the following:

1. Increase the government take in deep water consistent with Section 16 of the Deep Offshore Act comparable to international levels;


3. Make the collection process more transparent through the petroleum revenue information system;

4. Adjust the system to a modern international taxation framework. Overall Objectives of the Petroleum Fiscal Reform Bill (Oversight role for Federal Inland Revenue Service)

1. All Companies engaged in upstream petroleum operations should pay Company Income Tax, including NNPC and successors;

2. A resource tax is introduced, the Nigerian Hydrocarbon Tax (NHT), which is a simplified version of Petroleum Profit Tax (PPT);

3. Eliminates Tax Offsets and Upstream Investment Tax Allowances; 4. Reduction of deductible items in assessing NHT;



5. Introduces volume and price based royalties. Fiscal Tools Nigerian Hydrocarbon Tax (NHT, a simplified version of PPT):

• Applicable to all companies engaged in upstream petroleum operations;

• Rates: 40% onshore; 30% shallow water and 20% deep water;

• Production allowances limited by cumulative production and terrain and adjusted such that the tax burden on gas projects are minimised;

• Limited pool of Tax Deductible items;

• Maximum of 80% deductibility for costs incurred overseas;

• Same measurement point for royalty and taxes. Volume and Price based Royalties – Royalty Based on Volume

• All production is subject to royalties with clearer measurement point based on monthly production;

• Royalties in kind or cash with notice for gas royalties in kind;

• 5% minimum royalty for oil and gas production depending on production rates

• 20% maximum royalty for production above 50,000 bpd, accounting for terrain;

• 10% maximum royalty fore production above 1000 mmscf, accounting for terrain;

• 5% royalty for frontier areas for both oil and gas;

• Sliding scale royalty rates not applicable to producing fields in onshore and shallow offshore at effective date of bill.


• 0% royalty for crude oil price below $50/bbl; • A 0.2% increase for every $1 crude oil price increase above $50; • Threshold oil and gas prices indexed to account for inflation.

5.6. Examples of International Best Practice

5.6.1. Fiscal Policies of Other Oil Producers The major purpose of any fiscal policy is to maximise economic returns to a country while offering a balanced risk return to any investor using fiscal policy tools such as taxation, expenditure, investment and/or debt/surplus management. The following table shows the key points of the fiscal regime for a variety of oil producing nations, as a comparison to the fiscal regime of Nigeria.



Table 5: Fiscal Regime for Selection of Oil Producing Nations Norway Argentina Brazil Saudi

Arabia United

Kingdom Russia Netherland

FISCAL POLICY REGIME

Concession Concession Concession Concession Concession Concession

Concession

Applicable Taxes (Method of Tax Application)

• Profit-

based special taxes

• Corporate income tax

• Production sharing contracts

• Service contract

• Royalties • Profit-based

special taxes • Corporate

income tax


• Service Contract

• Royalties • Profit-

based special taxes



• Service Contract


based special taxes





based special taxes




• Royalties

• Profit-based special taxes





based special taxes




Depreciation Method (Capital Allowances)

• Offshore investments are depreciated over six years

• An additional 22% uplift applies against the special (resource rent) tax for upstream activities

Accelerated depreciation capital uplift

Depreciation deduction are calculated for each class of fixed assets by applying the prescribed depreciation rate to the remaining value of each group at the fiscal year-end

• Accelerated depreciation

• Immediate write-off for exploration costs

Accelerated depreciation Exploration costs are generally written off over 12 months

Capital uplift or credit immediate write-off for exploration costs

Investment Incentives

Losses from offshore activities may be carried forward indefinitely with interest

• Tax losses can be carried forward indefinitely

• Research and

• Losses may be carried forward indefinitely

• However, the maximum loss that

Losses can be carried forward indefinitely - R&D incentive

Research and development (R&D) credit (CIT), extra 25% deduction on capital investments



development (R&D) incentives

can be offset against a year’s profit is 25% of the tax-adjusted profits for that year

in qualifying small fields (SPS)4


5.6.2. Elements of Fiscal Policy to Offset Resource Dependency Elements of fiscal policy that can offset the impact of a natural resource dependent economy such as Nigeria are: 1. Best Practice Single Point Authority in Revenue Management (RM):

a) The proposed fiscal law will clearly uphold the best practice principle of a single point authority in revenue management by avoiding the introduction of powers such as exist under Section 6 of the Petroleum Act, which requires the Minister to set the prices of petroleum products across Nigeria;

b) Similarly, provisions such as exist in Sections 5, 6, 7 and 9 of the NNPC Act which: (1) Oblige the corporation to give effect to Federal Government Agreements without any qualified assessment of the financial impact on the corporation (Section 5:1h); (2) Allow the creation of additional entities within the corporation without specific requirements for funding and fiscal sustainability (Section 6); (3) Allow for the offset of all expenses against any funds held by the corporation as appropriated by the President (Section 7:4); and (4) Allow for “excess funds” to be transferred by the President from NNPC (Section 9) respectively[

c) A single point authority for revenue management will be considered within the remit of the Ministry of Finance and the collection agencies will be FIRS (taxes) and the independent regulator (royalties, fees, levies and rentals).

2. Creation of Financial Buffers: While Nigeria already has a Sovereign Wealth

Fund (SWF), funding under the provisions of the enabling legislation has proven difficult at best. Significant revenues could have accrued to the SWF if the political will had been in place to avoid them being spent on subsidy payments. At the Petroleum Ministry level, the Petroleum Fiscal Policy as it relates to the National Oil Company is that the National Oil Company shall agree an annual dividend policy with the Ministry of Finance for proceeds arising from its profits to be paid to the government and that the retained earnings consequent to this dividend policy shall be used for commercially sound investments. Similarly, with respect to any balance sheet financing for the National Oil Company the debt-equity ratio shall not exceed 30%.

3. Avoidance of Populist Economics: The new fiscal policy shall specifically

protect the National Oil Company from exogenous intrusions in terms of its



revenues. In other words, the government commits to market related pricing for crude and derivative products in the industry and price setting only in the case of Natural Monopolies such as pipeline and processing facilities, where prices shall be non-discriminatory and regulated on a rate of return basis. Additionally, government is committed to incentivising investment in domestic production through backward integration strategies in the oil and gas industry by extending Section 39 CITA Fiscal Incentives to all mid-stream oil and gas utilisation projects.

4. Revenue Diversification: The contribution of oil to GDP is about 15% (2012 data)

but the contribution to government revenues is about 82%. With declining oil revenues, the percentage of oil’s contribution to declining revenues will also decline. The reason for oil’s low contribution to GDP is that the industry is not well integrated with the general economy. In other words, processing of hydrocarbons and other value adding activities have been generally low in the economy. It is therefore the intention of the government’s petroleum fiscal policy to incentivise production and processing of hydrocarbons domestically and to ensure the creation of ancillary value adding industrial activities in the country. A four-pronged strategy is presented below; a) Create national focal point for developing industries beyond fuels; b) A clear fiscal system that is supportive of high value hydrocarbon spin-off

industries but not dependent on cost recovery from upstream oil activities; c) Right incentives through price deregulation in order to support a commercial

framework for the development of refineries; d) Industrial parks with pre-investment in infrastructure by the State.

Figure 19: Make Up of the Nigerian Economy

Source: National Bureau of Statistics; Analysis: MPR Petroleum Fiscal Policy Team 2016



Figure 20: Nigerian Oil Revenue vs Non-Oil Revenue (2010-2014)

Source: Federation Account Allocation Committee, Nigeria; Analysis: MPR Petroleum Fiscal Policy Team 2016

Although government has established various free trade zones in the country, these zones essentially do not have the distinctive features necessary to encourage investment. These features are shown below:

Table 6: Features of Free Trade Zone Clusters


The government welcomes ideas towards implementing the general features of industrial clusters and enhancing factors that enable investment in Nigeria. 1. Resource Diversification: Just as the petroleum fiscal policy is to encourage

revenue diversification, similarly the policy would enhance natural resource diversification from oil to gas (diversification of energy mix), from crude oil exports to value added oil activities and from fuels to non-fuels (full value chain diversification).



Figure 21: Gas Chain Diversification


Figure 22: Oil Chain Diversification

Source: MPR Petroleum Fiscal Policy Team 2016 6. FISCAL RULES OF GENERAL APPLICATION

6.1. Government Fiscal Philosophy The philosophy for the fiscal framework of the gas policy is to set fiscal rules that are clear, transparent, globally competitive and designed to incentivise all participants. The role of the government is seen as not to create economic distortions that confer an advantage on or favour any particular party.

The purpose of the petroleum fiscal framework is that the state will be fiscally neutral as far as the types of hydrocarbons to be exploited. The policy therefore is to make gas economically viable to exploit, by reducing the state burden and to make gas standalone, separate from oil. Hence, gas projects will be developed based on their economics and not dependent on or consolidated against oil income.



6.2. Introduction Fiscal Rules of General Application (FRGA) is the framework through which the interests of the state and that of the investor are codified. This is best articulated with respect to Resource-Rich Developing Countries (RRDC). In RRDCs, revenue applicability refers to some basic principles that assure all parties of a level playing field and by which the overall objective of value maximisation of natural resources can be achieved. An optimum fiscal regime is often a composite of trade-offs across different objectives:

• Early Revenues vs Investment Efficiency; • Progressivity vs Competitiveness; • Early fiscal revenues vs tax incentives that drive a critical mass of

investments. In general, the fiscal framework of FRGAs does not deal with exhaustibility (spending overtime) and volatility (spending in good times and bad times of resource revenues). Thus, FRGAs are of a limited remit unless they are accompanied by macroeconomic interventions which are exogenous to the design of the fiscal system.

Progressive and transparent fiscal regimes are generally considered to be more stable and credible and, depending on the fiscal design, they do not compromise on efficiency. FRGA are based on clarity and transparency which require that:

• Rules are established by law and contracts are published;

• Laws are consistent with the nation’s jurisprudence; • Laws and contracts minimise discretion;

• Government revenue streams should occur during all production periods but also should increase with a larger share of revenues as profitability increases;

• Progressive fiscal systems that arise from FRGAs should be based on: o Royalty (Early Revenues); o Regular Corporate Income Tax (CITA); o Tax on Rent (Hydrocarbon Tax).

Resource tax can be easier to administer by:

• Simplifying and consolidating the fiscal regime to few legal instruments.

• Adopting publicly available parameters to calculate the basis for taxation while accommodating specific fees, levies and royalties, etc.

Stable and credible fiscal terms must also demonstrate robustness in the face of volatilities of cost and price. Robustness means that the fiscal system for gas is not subsidised by oil and vice-versa. This can best be achieved through the right pricing of gas and lower royalties and resource tax. Additionally, FRGAs must deter transfer



pricing, encourage cost benchmarking and must be consistent with the nation’s international treaty commitments. The purpose of any sustainable fiscal policy is to maximise economic returns to the state while offering a risk balanced return to the investor. This presupposes that there is an understanding of the burden the state can impose on an economic activity such that the state does not suffer diminishing returns (The Laffer Principle).

6.3. Principles of the Fiscal Framework In the implementation of fiscal policy, the role of the state is critical, in other words the state must not compel commerce, rather it should regulate it. Therefore:

• The state should interest itself in what is done, not who does it;

• The state should not be involved in business risk activities, instead state involvement in investments should be limited to minority stakes in projects for the benefit of the national interest which are taken from a portfolio of possible projects.

The fiscal framework of the petroleum policy for Nigeria will be based around six key principles:

1. Right Pricing: Pricing should not be fixed by the state but there should be an interaction of the market to determine the right price (which is not necessarily a low price);

2. Sustainability: Fiscal policies must enhance investment, be cost efficient and sustainable in the long run;

3. Non-consolidation / Non-recovery of gas costs from oil income: The fiscal framework intends to remove the distortions in AGFA from the effective cross-subsidy of oil to the gas sector. The gas policy will therefore ensure that gas project costs are attributed to gas projects, and gas projects are standalone;

4. Separate Fiscal Treatments: At the same time, the government intends to have separate fiscal treatment for exploration, production and midstream gas activities, to relax royalty and tax rates for gas, and incentivise entry into the midstream. These are all designed to stimulate investment and ensure that gas projects can be economically viable from a fiscal viewpoint;

5. Upstream Incentives for Gas-For-Development: Upstream incentives to invest in gas-for-development (for example, to promote increased E&P activity in the onshore frontier areas by providing globally competitive incentives) can include the introduction of more favourable upstream terms for gas activities:

a. Reduced royalty rates for gas; b. Under Production Sharing Contracts (PSCs), introduction of more

favourable production allowances and hydrocarbon tax in the event of gas production;

6. Midstream Incentives: Fiscal policy incentives to attract investment into the midstream.



6.4. Thematic Areas to be Addressed in a Fiscal System

Seven main thematic areas that must be addressed in the fiscal system are as follows:

1. Governance: The key governing institutions of the oil and gas industry and their role as prescribed by the separation of policy regulation and commercial operations;

2. Funding: Funding of the institutions and funding of government participation in commercial operations;

3. Fiscal incentives for investments: The balance of risk and reward in a fiscal framework;

4. Enabling gas exploitation: Enabling gas exploitation in Nigeria through policy regulatory and fiscal interventions;

5. The role of the regulator: The principles, powers and economics of regulation;

6. The role of the state in natural resource management: Shareholder responsibilities versus requirements to meet social needs;

7. Mitigating social consequences of natural resource exploitation: Best practice community participation.



7. FISCAL OBJECTIVES AND FISCAL INSTRUMENTS

7.1. Regressive and Progressive Fiscal Terms Modern fiscal systems try to be more progressive with a move towards tax based incentives and taxes on profits.

Table 7: Regressive to Progressive Fiscal Terms

Fixed terms Royalty Cost Tax Based Incentives

Profit

• Domestic obligations

• Signature bonus

• Production bonus

• Fees

• Rents

• Royalties based on:

o Flat Rates

o Price based

o R Factors

o Water depth based

o Other RoR based schemes

• Domestic obligation

• Deductible/

• Non deductible

• Cost Recovery Limits

• Cost Uplift

• Cost Consolidation/ Non consolidation

• Investment tax credit

• Investment Tax Allowances based on W.D

• Production Allowances based on W.D

• Resource Tax based on W.D or R-Factor based on price (MOU)


• Profit oil based on:

o Production rate

o Cumulative Production

o R factor based

o Water depth based

Source: MPR Petroleum Fiscal Policy Team 2016 Choosing the right mix of fiscal objectives and instruments to ensure a progressive petroleum fiscal regime is discussed in this section of the policy.

Regressive Progressive Progressive



Table 8: Regressive to Progressive Fiscal Terms, Choosing the Right Mix

Fiscal Objective Preferred Instruments

Rent Capture / Progressivity

Progressive taxes or production shares, ideally rate of return-based. Service fees

Fiscal Neutrality / broad-based development

Profits-based taxes. No cross subsidy from oil to gas and vice-versa

Robustness / Adaptability Progressive taxes or production shares, ideally rate of return-based

Early, dependable revenue Royalties. Setting minimum percentage of profit oil, i.e., limiting annual share devoted to cost recovery

Limited risk exposure Royalties

International competitiveness / Balance of Objectives

Impact of overall mix of instruments is critical

Simplicity / Transparency Royalty. Taxes or shares linked to easily observed indicators/Fiscal Rules that are published

Cost Curtailment Cost Recovery Limits, Production Allowances instead of ITA, Lower Tax Rates


Economic Rent This is the difference between the payments received by a resource owner and the opportunity cost of the resource. In other words, payment received by a resource owner over and above the minimum needed to produce a good. Many resource owners are able to extract a portion of the economic profit generated by a business as economic rent. Optimizing economic rent to the owner (state) requires an optimization of the burden the state can impose on extraction activities. In the oil industry, this is the difference between the Gross value of the production and the cost of producing that resource (cost of supply) including an allowance for a normal rate of return on investment. What is considered a normal rate of return on investment may vary from project to project and/or company to company.



In the schematic shown overleaf, economic rent is expressed as Gross value of Production less the Investment and Operating costs giving what is called Divisible Income or Project Economic Profit; less the return on Investment for the investor. This is also sometimes referred to as State Take (or Government Take). A fiscal regime therefore determines how the Divisible Income is split between the resource owner and the investor. Economic Rent should not lead to potentially profitable projects being deferred or cancelled. Economic rent may change the relative ranking of differently structured projects.

All commercial negotiations seek to strike or establish a fair balance between the economic rent and investors return on investment. (See figure 1)

7.2. Capital Gains Tax

The proposed new legislation will increase the Capital Gains Tax rate in respect of asset based transactions from 10% to 30%.

This would be in line with other jurisdictions especially in Africa where they vary from 20% - 40%.

Figure 23: Rent Capture through Capital Gains Tax, African Countries

Source: NNPC CP&S 2014

Resource rich countries generally have higher Capital Gains Tax (CGT), for example: South Africa (Gold & Diamonds), Botswana (Diamonds) and Zambia (Copper). Angola which is an oil and gas provenance has a capital gain stands similar to its corporate



income tax of 30%. The government of Nigeria intends to amend the capital gains tax act for oil and gas transactions to be at a rate similar to the corporate income tax which is currently 30%.

7.3. Fiscal Neutrality and Broad-Based Development

Fiscal terms for Upstream, Midstream and Downstream are expected to stand on their own merit. Under the proposed new fiscal strategy, the requirement for fiscal neutrality is enhanced. Fiscal neutrality means each segment of the value chain does not lean on the other, similarly the economics of gas across the value chain should not rely on cross subsidies from oil.

Gas capital and operating expense recoveries from oil as per AGFA will no longer be available for all projects; so Sections 11 & 12 of the Petroleum Profit Tax Act (PPTA) as amended stands abrogated.

Fiscal terms for Upstream, Midstream and Downstream are expected to stand on their own merit. Tax consolidation across the value chain is avoided by limiting cross subsidies which tend to favour existing players and hinders broader participation by other investors. This also means that apart from non-consolidation across the value chain, gas projects do not lean on oil projects for fiscal robustness. In particular, transfer pricing mechanisms that have the effect of reducing Government revenues are discouraged. Under the proposed new fiscal strategy, the requirement for fiscal neutrality is enhanced. Fiscal neutrality means each segment of the value chain does not lean on the other, similarly the economics of gas across the value chain should not rely on cross subsidies from oil. In the light of the foregoing, Sections 11 & 12 of the PPTA as amended stands abrogated:

• Gas capital and operating expense recoveries from oil as per AGFA will no longer be available for all projects;

• Mid-stream and downstream projects whether in oil or gas cannot be recovered from upstream project revenues;

• Investments made pursuant to the defunct Sec. 11 and Sec. 12 of the PPTA shall remain eligible for treatment under these provisions subject to the expiration of the capital allowances earned thereto;

• Pursuant to the above, all new projects shall be subject to the provisions of the new law upon enactment.

In order to enhance fiscal neutrality across the entire oil and gas value chain, specific mid-stream fiscal incentives are also proposed in the law:

1. Section 39 of Company Income Tax Act (CITA) will be amended to include mid-stream oil utilisation in addition to gas utilisation projects. By this move, mid-stream oil processing (refineries) infrastructure, oil pipelines, storage systems, etc. will be subject to the provisions of Section 39 of CITA. Based on



this, consolidation of mid-stream terms will no longer be permitted for either gas or oil projects.

q In order to reinforce fiscal neutrality, clear definitions of upstream oil and

upstream gas operations, distinct from mid-stream oil and mid-stream gas operations are to be incorporated into PIRB legislations (and likewise for downstream oil and downstream gas operations). As a result, a clearer definition of upstream as distinct from mid-stream activities will be provided for in the envisaged new legislation.

q In removing AGFA provisions the government intends to reduce the royalty and tax burdens on gas projects and also propose a more market oriented gas pricing methodology for the industry, the aim of which is to right-price gas.

q Negative government take for gas projects which is often further accentuated by tax holidays would be avoided. (see chart)

q By removing AGFA, the dependency of gas projects on oil income would be removed and this ought to lead to greater participation by companies that do not have tax capacity in oil (under the principle of equity in taxation).

Figure 24: Gas Government Revenue Chain

q The gas project in the upstream under AGFA generates negative government take. Proposed changes in the fiscal policy will put a stop to the unsustainable fiscal incentive abuse.

q When transferred to a midstream facility with a tax holiday, taxes are deferred under CITA section 39 for upwards of 8 years (in the LNG case, about 15 years.



q If that gas is delivered to a fertilizer plant which is eligible for pioneer status under the industrial development income tax relief act, this could result in the deferred tax of further 8 years.

2. Based on the following, the entire gas value chain ends up delivering very little by way of government take except government is an investor in this business.

7.4. Convergence and Divergence in Oil and Gas Prices The proposed Fiscal regime is adaptable to the convergence and divergence in the prices of crude oil and natural gas as evident in the chart above by the linking of fiscal prospect activities of gas from oil. In other words the fiscal tolls for gas have been designed as standalone without relying on consolidation with oil revenues. In any case following the recent collapse in oil prices, the tax capacity of oil projects have significantly declined, and may no longer accommodate AGFA terms for gas.



Figure 25: Crude and Natural Gas Prices, 1995-2015

Source: BP Annual Statistical Review 2016; Analysis: MPR Petroleum Fiscal Policy Team 2016

7.5. Early Dependable Revenue Royalties remain the backbone of Government Revenues in any resource based fiscal system because these are the first charges on petroleum when it is produced. They represent a volume of petroleum due to the owner as prescribed by the constitution. Although Royalty can be retrogressive, a Royalty by volume scheme can be made progressive by the Royalty rate increasing with the production rate. Similarly, the royalty can also vary with hydrocarbon prices. This is often called the windfall feature when dramatic swings in hydrocarbon prices are evident. Again progressivity can be introduced in the royalty by price scheme. Additionally, royalty represents a very simple method for calculating Government Take because as the first charge, cost and tax computations do not affect it. It follows therefore, for a resource rich developing economy, under NO circumstances should royalty be 0% or royalty holidays be granted. The following figure shows Royalty Rates by Oil Price to illustrate the windfall feature, and Royalty Rate by volume to illustrate the Progressivity of the Royalty regime.



Figure 26: Royalty Rates by Oil Price

Source: MPR Petroleum Fiscal Policy Team 2016 The design of the PIRB fiscal regime is based on the premise of incentives being granted to small fields at low prices and windfall profits captured through price based royalties. A price-based windfall is compensated for by a lower Government Take when prices are low and fields are small. The government take for the JVs remains essentially unchanged.

Figure 27: Investor Margins at Varying Oil Prices PPTA and PIRB

Note: Investor Margin refers to NCF per BBL Source: MPR Petroleum Fiscal Policy Team 2016 PPTA = Petroleum Profits Tax Act; PIRB = Petroleum Industry Reform Bill



Figure 28: Government Take as %age of Oil Price under PPTA and PIRB

Source: MPR Petroleum Fiscal Policy Team 2016 PPTA = Petroleum Profits Tax Act; PIRB = Petroleum Industry Reform Bill

7.6. Limited Risk Exposure By limiting the Government to post-exploration participation, the risk of upfront expenditure on exploration is minimised. Similarly, by basing Government Take principally on Royalties and less on Taxes, the Government eliminates “gold plating” costs and improves the Savings Index (SI). There are many types of risk in the Oil and Gas value chain: Structural Risks: The State often needs an entity to participate in Oil and Gas activities. This can take the form of a national oil company (NNPC) or an investment vehicle (NAPIMS or PETORO, the Norwegian state asset management company, the Norwegian version of NAPIMS). The potential risks associated with the structure of these entities can be significant. Fiscal Risks: While there are potential benefits of participation, governments are not generally known to be good managers of risks. A National Oil Company (NNPC) that participates on behalf of the State in actual operational and financial activities leads inevitably to exposure to these risks. Operational Risks: This could come about through participation and operatorship by the NOC. For example, if the penalties arising from the BP Maconda Oil spill were to be applied to an NOC like NNPC, the entire balance sheet of Africa’s largest corporation would have been wiped out. Financial Risks: Institutions of the state are constantly competing for State resources. While Oil and Gas investments often offer top class returns, these financial commitments may interfere with spending in other vital areas.



7.7. Review of PSC Terms The Deep Offshore Act provides for a review of 1993 PSC terms any time oil prices exceed $20/bbl real, so as to compensate the government from incremental revenues arising from higher oil prices. Since 2003, oil prices have exceeded $20/bbl without the government obtaining a fairer share of the incremental revenues.

Figure 29: Comparison of Government Take in some Deep Water PSCs, 2010

Source: MPR 2010

Under the Petroleum Fiscal Policy, PSC Terms will be reviewed, consistent with the provisions of the Deep Offshore Act.

7.8. Simplicity of Royalty and Tax Collection Natural resources should be governed by a comprehensive legal framework with a fiscal regime including open and transparent procedures for granting rights for extraction, plus clear rules governing resource revenue generation and collection. IMF best practice is that government and the resource company are required to provide comprehensive, timely and reliable reports on:

• Holdings of natural resource rights; • Extraction trading activities; • Payment and collections of resource revenues (Extractive Industry

Transparency Initiative, EITI). Royalty and tax collection is simplified through:

• Shifting the emphasis of revenue collection towards more rents and royalties and less on taxes;

• Reducing the “tax nature” of the Petroleum Profits Tax (PPT) by splitting the PPT into:

o A Nigerian Hydrocarbon Tax (NHT) which will be easier to administer;



o Companies Income Tax (CIT), which will now be paid by all companies involved in the petroleum industry;

o Making NHT not deductible for CIT purposes; • Determining royalties, NHT and production sharing all on the same production

based revenues. Windfall profits are captured by:

• Establishing a new royalty scheme, with a royalty in kind or cash, whereby the total royalty rate can vary between 5% and 40%, based on:

o Royalty scale based on daily production, which will range from 20% to 25%; o Royalty scale based on price, which will range from 0% to 20%; o No royalty based on gas price.

• Creating a higher overall government take on profitable large fields under high prices, through royalties, Nigerian Hydrocarbon Tax and Companies Income Tax.

7.9. Transparency There is a wide variety of fiscal tools that can be used for the purposes of rent capture, however for Resource Rich Developing Economies (RRDE), computationally simple tools are preferred. Some of these tools include Royalties, Production Bonuses, Linear Tax systems (proportionate tax methodologies) vs. non-linear such as R-factor or RoR based systems. As part of this simplification, the government intends to publish royalty templates under proposed regulations pursuant to the proposed fiscal law. Furthermore, consistent with the NEITI Act, a management information system which will cater for petroleum revenue information will be developed within the Ministry of Petroleum Resources. The basic preference that a fiscal system must honour is that such systems must conform to the general jurisprudence with regard to the fiscal laws to stand a better chance of meaningful implementation.



Table 9: Fiscal Transparency Principles




7.10. Cost Curtailment and Improving Cost Efficiency After the recent high oil prices which had impacts on costs, a principal objective of any petroleum fiscal system is how to improve cost efficiency in the industry. In the Nigerian case, the high oil prices were coupled with high costs of security. The preference for fiscal tools such as cost recovery limits, choice of production allowances rather than cost based incentives, lower taxes to improve the savings index and cost benchmarking (for the midstream for tariff setting) are all market driven tools which enable cost efficiency at the industry wide level. 8. OTHER FISCAL INSTRUMENTS

8.1. Right Gas Pricing Unlike oil prices which apply globally, natural gas prices are regional and sometimes do not exhibit exact commodity price futures. The chart below shows how pricing for the USA, Europe and Japan have moved apart in the ten years between 2002 and 2015.



Figure 30: Global Gas Price Movements (1998-2015)

Figure 31: Monthly Gas Price Movements at Major Pricing Points (2015-2016)

Source: BP Statistical Review of World Energy, 2016

Source: US EIA 2016; IMF 2016; World Bank Commodity Markets Review Report 2016; Analysis: MPR Gas Policy Team 2016

For Nigeria, the gas pricing policy is now being integrated into gas fiscal terms so as to ensure the right pricing of gas and non-consolidation of gas expenditure with oil income. To this end, the gas pricing regulations of October 2008 is being reviewed and the provisions expanded to cover gas recovered from the flare, and gas produced and sold to LNG projects or other stranded gas to stranded industry projects. Transitional gas pricing arrangements will be in place until gas market liquidity has been achieved. The measures for determining that gas market liquidity has been achieved are set out in the National Gas Policy, a complementary policy to this Petroleum Fiscal Policy.

8.2. Transitional Pricing Arrangements

8.2.1. Strategic Domestic Sector (Gas to Power) The Gas Price to Power (CPy) = $2.50/MMbtu effective from January 1st, 2016. Thereafter, with effect from the period commencing on January 1, 2017, the applicable Contract Price shall be calculated and adjusted in accordance with the following indexation formula:

Where:

CPy = Contract Price applicable for the relevant Contract Year; CPy-1 = Contract Price for the immediately preceding Contract Year; CPIp = OECD-Total: Consumer Price Index - All items, in effect for the six (6) month period ending three (3) months before the start of the relevant Contract Year;



CPIp-1 = OECD-Total: Consumer Price Index - All items, in effect for the six (6) month period ending three (3) months before the start of the immediately preceding Contract Year.

The Gas Price to Power is based on the provision that the Contract Price shall immediately be capped by the Export Parity Price (EPP) or amended in line with any directive by the Minister, applicable to this Sector, prescribing new prices for Gas supplied to the power sector, pursuant to the National Domestic Gas Supply and Pricing Policy 2008.

8.2.2. Strategic Industrial Sector/Gas Based Industries (GBI)

The Gas Pricing to Gas Based Industry (CP) has a stipulated floor price of $0.90/MMbtu (RT2011) and capped gas price of $3.00/MMbtu (RT2011) and is calculated as follows:

(RT2011) and is calculated as MMbtu (RT2011) Where:

CP is the applicable gas price in $/MMbtu; NRP is the National Reference Price which is $0.90/MMbtu (RT2011); EPF = (CMPP – PRP)/PRP (The End Product Factor); CMPP is the Average Current Month End Product Price in $/MT; PRP = Product Reference Price in $/MT (varies depending on the industry).

*Prices should be adjusted by OECD annual average inflation rate, published at: http://stats.oecd.org/Index.aspx?DataSetCode=MEI_PRICES# The applicable current year (n) prices are adjusted as follows:

CPI( n-1) / CPI(2011) Where:

(n-1) is the immediate prior year OECD - Total annual average CPI for all items.



Table 10: Table for Product Reference Price for Gas Based Industries


8.2.3. Flared Gas Gas recovered from the flare, pursuant to paragraph 35b of the first schedule of the Petroleum Act (as amended) not exceeding 10mmscf/d and delivered through a mid-stream transportation and/or processing facility shall be priced at $0.25/mcf effective from January 1, 2017. With effect from the period commencing on January 1, 2017, the applicable Contract Price shall be calculated and adjusted in accordance with the following indexation formula:

Where: CPy = Contract Price applicable for the relevant Contract Year; CPy-1 = Contract Price for the immediately preceding Contract Year; CPIp = OECD-Total: Consumer Price Index - All items, in effect for the six (6) month period ending three (3) months before the start of the relevant Contract Year; CPIp-1 = OECD-Total: Consumer Price Index - All items, in effect for the six (6) month period ending three (3) months before the start of the immediately preceding Contract Year.

Provided that the Contract Price shall immediately be amended in line with any directive by the Minister, applicable to this Sector, prescribing new prices for Gas supplied to the power sector, pursuant to the National Domestic Gas Supply and Pricing Policy 2008.

8.2.4. Gas Pricing to Wholesalers/Local Distribution Companies The Gas Pricing to Local Distribution Companies (Cp) has a stipulated capped gas price of $3.00/mcf (2014) and is calculated as follows:

(Cp)= [(0.7*1000*(Pfuel-oil * 1050/38,330))/400] – 4.0 Where:

Cp = applicable gas price in $/mcf;



Pfuel-oil = monthly average fueloil price (Naira/ltr) for applicable month (based on PPMC published prices); 1050 Btu = heating value of 1 scf of natural gas; 38,330 Btu = heating value of 1 ltr of fuel oil; 0.7 = natural gas discount factor relative to LPFO (70%); 4.0 = upstream correction factor.

Notwithstanding the foregoing formula, the Cp will be capped as follows:

Calendar Year 2014 US$ 3.00/mscf. With effect from the period commencing on January 1, 2015, the applicable cap to Contract Price shall be calculated and adjusted in accordance with the following formula:

CP = PP x CPIp/ CPIp-1 Where:

CP = current applicable cap; PP = the cap for the immediately preceding Contract Year; CPIp = OECD Consumer Price Index - Total, All items, in effect for the 6 month period ending three (3) months before the start of the current Contract Year; CPIp-1 = OECD Consumer Price Index - Total, All items, in effect for the 6 month period ending three (3) months before the start of the previous Contract Year.

8.2.5. Commercial Pricing for LNG/CNG

Under the Regulations, Upstream Gas price to LNG plants shall be based on the Export Parity Price (EPP) which is the weighted average price of gas sold to the NLNG plant at Bonny. Export Parity Pricing (EPP): The EPP is defined as the weighted average prior-year annual price ($/MMbtu) of total GSAs signed by upstream suppliers to LNG (excluding liquids).

EPP = {(GSA1*V1 + GSA2*V2 + GSAn*Vn)} / {(Total Annual Delivered Volume)}. Where:

EPP = Export Parity Price; GSA = Gas Sales Agreement; V = Contract Volume.

This shall be the Nigerian reference marker. It is a market driven pricing framework, responsive to fiscal changes and weighted to ensure pricing flexibility while moderating swings to protect fragile domestic industries



The current year price shall be computed as the prior year price of NLNG contracts for gas exported and sold and advised to the Gas Aggregator. This pricing framework shall remain in effect until gas market liquidity is established or until declaration by the Honourable Minister of full price deregulation.

8.2.6. Gas Transportation Tariff The Federal Ministry of Petroleum Resources, in exercise of its responsibility under the 2008 National Gas Supply and Pricing Regulations to “ensure equitable and transparent access to the gas transportation network”, formally approved a gas transportation tariff of $0.8.MMSCF applicable to the entire gas transportation network. The effective date of the new Gas transportation tariff is 1st January 2016. With effect from the period commencing on 1st January, 2017, the applicable cap to Gas Transportation Tariff shall be calculated and adjusted in accordance with the following formula:

CP = PP x CPIp / CPIp-1 Where:

CP = Contract Price; PP = Producer Price; CPI = Consumer Price Index.

8.3. Incentives for Low Cost / Small Fields Low cost operations will be encouraged by creating more profits for efficient operators relative to inefficient operators. This will be achieved through:

• Placing more emphasis on royalties (where costs are not deducted);

• Streamlining the Nigerian Hydrocarbon Tax by: o Removing the investment tax allowances and investment tax credits; o Removing deductibility of interest; o Increasing the amount of non-deductible costs; o Lowering the PPT rate in the form of Nigerian Hydrocarbon Tax rate.

The development of small fields will be encouraged by:

• A 5% royalty on small fields based on average daily production for the month; • Significant allowances under the Nigerian Hydrocarbon Tax that will reduce the

tax rate to 0% for small fields.



8.4. Fiscal Incentives for LPG

8.4.1. Gas Utilisation Incentives LPG as part of the gas value chain ought to be covered by the gas utilisation incentives intended for midstream projects as LPG appears as a result of midstream oil refining or gas processing. These include LNG, manufacturing of LPG cylinders as well as LPG related infrastructure. Consequently:

In order to implement fiscal rules of general application, Section 39 of CITA will be amended to include LPG projects and LPG infrastructure.

The state should not be creating economic distortions in the energy market place. There are currently distortions where VAT is charged on LPG and not on other competing fuels. Rather than removing VAT from LPG, the fiscal policy states that under our general fiscal applicability rules, exemptions from VAT for other competing fuels should be reversed.

8.4.2. LPG Pricing Policy The policy for LPG pricing is:

• Market Driven: Prices set by the market; • Dominant Supply Price Rule: Export Parity Pricing;

• LPG Retail Price: o EPP (Ex-NLNG) + o Ship to Terminal Tariff + o Storage and Distribution Tariff + o Cylinder Fund + o Retailers Margin.

8.4.3. Fiscal Incentives for LPG

The fiscal policy for all energy sources is to enable clear price transparency across competing fuels. The removal of the kerosene subsidy therefore competitively enhances the value of LPG. Additionally, the removal of the Kerosene subsidy incentivises switching programmes from kerosene to LPG and other fuels. The LPG pricing formula recognises the inclusion of tariffs for infrastructure, including jetties, transportation trucks, delivery terminals, storage depots etc. These tariffs will be regulated based on using benchmark or standard costs and Rate of Return (RoR) regulations. The Target RoR for any midstream infrastructure will be set at 12%-15%.



All LPG infrastructure, including cylinder manufacturing activities, terminals/jetties, pipelines, storage and distribution systems will now enjoy section 39 of CITA benefits. Fiscal incentives for LPG will be meaningless if the midstream infrastructure continues to hinder accessibility, availability and affordability of LPG. Therefore, regulatory and structural reform of the LPG midstream is high priority.

8.4.4. Petroleum Products Pricing Policy The Government’s policy on petroleum products pricing is best done to well establish linkages to crude oil and its petroleum pricing derivatives. These linkages can be market determined through regression analysis of historical market traded data. This has formed the basis of the derivation of the PPPRA Product Price Template. The results of a typical regression for four products (PMS, AGO, Jet Kero and Fuel Oil) are indicated below: Figure 32. Relationship between Crude Oil price and Petroleum product price

The regression analysis which indicates over 95% correlation in most cases between crude prices and product derivative prices is an indication that petroleum product prices can be predicted once crude prices are known. Arising from the above, government’s intention has been not only to withdraw from setting petroleum product prices but rather enabling the markets to determine prices. It is government’s view that the role of the market is to encourage economic efficiency, economic choices and economic growth which will ultimately be beneficial to investments across the petroleum products value chain. The government intends to encourage market deregulation with its attendant features of improved competition in the pricing of petroleum products (see table below).



Table 11. Improved competition on Petroleum products pricing.

Consequently, the proposed pricing framework for petroleum products is as indicated below:

This pricing framework ensures transparency and a rule based approach to competitive product prices. Where of course there are natural monopolies, e.g. pipelines, etc. in the transportation and distribution end of the value chain, the government expects the regulator to impose a tariff based on a methodology not far removed from what is suggested below i.e. an RoR based tariffing methodology. This is indicated in the chart below:



Figure 33: Computation of Midstream pipeline Tariff.

9. COSTS AND PRICES 9.1 Cost Price Ratio: cost control tax inversion penalty & lower hydrocarbon tax.

If cost exceeds 30% of revenue, profit declines and in terms of the time value of money (in Net Present Value (NPV) terms) the project becomes uneconomic. With a cost price ratio of 30%, the investor receives 17.5% of total revenues while the government take is 52.5% of total revenues. However, when the time value of money is computed, this can effectively limit the returns to single digits, which makes the investment a challenge.

q Technical Cost, T1 +T2, will be capped at thirty percent of the oil tax i.e. cost tax ratio will be 0.3.

q All costs above the targeted cost-price-ratio (C-P-R) will be recovered at a lower tax rate (the tax inversion penalty rate).

q Savings Index significantly improve through lower hydrocarbon tax.

q Procurement cycle to be significantly reduced by requiring regulator to demonstrate the benefits of any regulatory stance through cost-benefit analysis/economics. This is to limit regulatory capture.

Within this context, Nigeria’s fiscal regime is often designed according to the simple rule that the C-P-R should not exceed 30%.

9.2 2016 Petroleum (Fiscal Reform) Bill Terms

The royalties, tax rates and production allowances under the Petroleum Fiscal Policy are set out as follows:



9.2.1 Reliance on Royalty for Government Take Instead of Taxes q Consistent with Section 16 of the Deep Offshore Act which for the purposes

of the new legislation will be preserved, the government proposes to introduce a royalty by price scheme which will vary with oil price increases in order to capture windfall profits.

q The royalty by price scheme shall apply to oil prices above $50/bbl but shall not apply to natural gas.

q Royalty rates by volume for oil and gas will vary from 5% upwards, except that for natural gas royalty rate by volume shall not exceed 10%.

Figure 34: Proposed Royalty Rates for Oil.



9.2.2 Improved Fiscal Terms for Midstream Oil & Gas Investments q Section 39 of CITA shall be amended to include mid-stream oil operations

such as refineries and other oil processing facilities and transportation pipelines.

q Where such transportation are regarded by the regulator as natural monopolies, the regulated tariff shall be set on the basis of a fair and reasonable return which may not be below 20% nominal.

q The fiscal incentive for midstream is intended to treat all hydrocarbons in midstream operations on similar fiscal basis and allow the market to select preferences.

9.2.3 Removing the Deductibility of Acquisition Costs Under Qualifying Capital Expenditure

q Under qualifying capital expenditure in the PPT, acquisition costs can be deducted. As a result, all the recent Shell divested transactions has resulted in the government actually paying for the acquisition.

q When combined with low capital gains tax and tax holidays and pioneer status granted to acquiring parties, this would result in tax reduction estimated at $21 billion.

q The series of chart overleaf illustrate this point.



The combined effect of tax holiday and unlimited tax loss carry forward means that 2019 will be a cataclysmic year in which about $9.4bn in taxes will be eligible to be deducted. From our calculations, all the divested assets in 2014 and 2015 that have been given 5 year tax holidays will not be eligible to pay taxes until 2023. The graph above shows taxes forgone by the Government as a result of the tax policy. A total of $21.9bn from 2014 to 2019 would be lost as a result of divestment.

9.2.4 Removing Gas Flare Penalties from Qualifying Deductions q Gas flare elimination project to be launched December, 2016. Proposed

amendment of the PPT Act would remove deductibility of the flare penalty.

q Gas pricing regulation would set gas flare price at no less than 25cents per MMSCF.

q Potential opportunity for significant revenues to the state post tax holiday.



q Flare elimination to help address climate change and community unrest.

Potential for community participation through carry arrangements would enhance economic development of the Niger Delta.

9.2.5 Requiring Economic Efficiency Tests for Regulations In Order To Improve Regulatory Rule Setting

9.2.6 Avoiding Fiscal Incentives Abuse

q Analysis of investment incentives across the globe shows that the most effective incentives are rule based incentives that preserve the principle of equitable taxation and avoids chronic capitalism.

q Ranking of key investment criteria in studies done by World Bank and IMF, shows the following:

q Investors consider economic stability, political stability, cost of raw materials, local markets, transparency of legal framework, availability of skilled labor, labor costs, quality of life, availability of local suppliers, bilateral agreements and treaties before incentives package.

q However, Nigeria has incentives package and raw materials as its two top considerations. This is why incentives are not aligned with investor expectations.



Figure 35: Key Factors that Influence Foreign Investors.

By using smartly targeted fiscal incentives, Nigeria can avoid the current misalignment between fiscal incentives and investor needs.

9.2.7 Competitiveness of PIB 2016 Terms There are often various criteria’s used to determine competitiveness in the Oil and Gas sector. Some of these include:

• Cost recovery Limit • Government Take • Investor IRR



9.2.8 Cost Recovery Limit

Figure 36: Comparison of Cost Recovery Limit.

q Cost Recovery is a key feature of the Production Sharing Agreement or Contract (PSA/PSC) and refers to the concept whereby a contractor recovers his costs from production net of royalty in the form of cost oil (usually)

q Typically, after the deduction of cost oil from production, the residual is Profit Oil on which the Contractor and Concessionaire can share on the basis of cumulative production, Rate of Return Or R-factor. The concessionaire pays Tax on his portion of Profit Oil

q Clearly the manner and quantum of Cost Recovery is critical to the amount of Profit Oil available to be shared and the quantum of Tax derivable from the arrangement

q Consequently, the following can be implemented in a fiscal design: q Provide a List of what qualifies as Non-deductible Costs q Provide a Cap or Limit of how much Cost can be recovered in a given

period, expressed as a percentage of Production less Royalty q Specify for how long unrecovered costs can be carried forward (until fully

recovered or until end of lease) The objective of the aforementioned actions is primarily to ensure that as early as possible within the PSC arrangement, there's a pool of Profit Oil which can be shared and Taxed.



9.2.9 Government Take Figure 37: Competitive Analysis of Comparison of Government Take and Investor Rate of Return (IRR).

9.2.10 Investor Internal Rate of Return (IRR) The 2016 fiscal terms yields robust economic for cases in which the cost price ratio does not exceed 30%. The indicative economics is also comparable with the 2014 effort. Figure 38: Fiscal Regime Analysis of Investor PVR and IRR.



9.3 COMPARISON OF FISCAL TERMS: CURRENT, 2014 PIB & PIRB 2016

Table 12: Fiscal Terms table.

9.3.1Tax Rates, Royalties Table 13: Tax and Royalty Rates under the Petroleum Fiscal Policy




9.3.2 Production Allowances Table 14: Production Allowances under the Petroleum Fiscal Policy




9.3.3 Comparison of Royalty, NHT, Production Allowances between PIB 2014 and PIRB 2016

The following charts compare the 2016 and 2014 fiscal terms. The charts show that the 2016 fiscal proposals regarding royalty rates show slightly higher royalty rates at higher production and prices compared with 2014 but lower tax rates.

Figure 39: Comparison: Oil Royalty by Production, Onshore


• PIRB 2016 retains the Royalty Profile same as PIB 2014 up to the last tranche; • Left Hand (LH) Graphic is Royalty tranche while Right Hand (RH) Graphic is

Sliding Scale. The following charts show the effect of these changes.

Figure 40: Comparison: Oil Royalty by Production, Shallow


• PIRB 2016 retains the Royalty Profile same as PIB 2014 up to the last tranche;



• Left Hand (LH) Graphic is Royalty tranche while Right Hand (RH) Graphic is Sliding Scale.

Figure 41: Comparison: Oil Royalty by Production, Deepwater


• PIRB 2016 retains the Royalty Profile same as PIB 2014 up to the last tranche; • LH Graphic is Royalty tranche while RH Graphic is the Sliding Scale; • For Deep-water, there is little difference between the effective royalty rates for

PIB 2014 and PIRB 2016. Figure 42: Comparison: Oil Royalty by Production, Price


• PIRB 2016 proposes to move back the trigger price for Royalty by Price to kick in; • Furthermore, PIRB 2016 reduces the PA to an average of approx. 18%

compared to PIB 2014 of ~27%.



Figure 43: Comparison: Gas Royalty, Onshore


• PIRB 2016 proposes to increase Royalty Rates but maintains the triggers; • LH Graphic is Royalty tranche while RH Graphic is the Sliding Scale.

Figure 44: Comparison: Gas Royalty, Shallow


• PIRB 2016 proposes to increase Royalty Rates but maintains the triggers; • LH Graphic is Royalty tranche while RH Graphic is the Sliding Scale.



Figure 45: Comparison: Gas Royalty, Deepwater


• PIRB 2016 proposes to increase Royalty Rates and in the DEEPWATER,

creates more steps; • LH Graphic is Royalty tranche while RH Graphic is the Sliding Scale.

Figure 46: Comparison: NHT

Source: MPR Petroleum Fiscal Policy Team 2016 • Note that PIRB 2016 NHT are generally lower than proposed in PIB 2014; • CIT is same between both regimes at 30%.



Figure 47: Oil Royalty by Production


• PIRB 2016 retains the Royalty Profile same as PIB 2014 up to the last tranche.

Figure 48: Gas Royalty


• PIRB 2016 proposes to increase Royalty Rates but maintains the triggers, and

in the DEEPWATER, creates more steps. 9.4 Draft Fiscal Analysis Test Examples The economic results show that the proposed fiscal regime delivers project returns in excess of 12% (Internal Rate of Return, IRR).



Table 15: Draft Fiscal Analysis Test Examples


Figure 49: Draft Fiscal Analysis Test Examples




10 COMMUNICATIONS

Introduction Communications are important parts of any policy. There are two fundamental purposes for communication of the petroleum fiscal policy to all stakeholders in Nigeria and abroad:

1. Explaining the policy; 2. Changing attitudes.

The Nigerian people, industry, international investors, even members of the government itself, have become to a certain extent sceptical or cynical about reforms in the energy sector. On numerous occasions there have been pronouncements from various parts of government announcing an end to power shortages or fuel crises, but with no apparent change. There also exists a gulf and lack of understanding between investors and government of their respective expectations and obligations.

A communications strategy will be developed as part of the Nigerian petroleum fiscal policy to explain to all stakeholders the purpose of the petroleum policy, and the thinking and analysis behind it.

Audiences need to understand that the petroleum policy is not a promise of when the lights will stay on. Instead it is to show that the Nigerian government is clear on what it wants to achieve, the reasons why and the steps to achieve the policy objectives. The petroleum policy will be communicated as a process to arrive at a long-term vision for the nation. The communications strategy will consist of two parts:

• Internal communications – audiences within government; • External communications – other stakeholders involved with the gas industry.

10.1 Internal Communications

10.1.1 Ministry Policies succeed or fail through the efforts of the civil servants and it is important that they are keen and active participants in the policy. The first task therefore is to explain the policy and its implication to stakeholders within the Ministry of Petroleum Resources. As the government body directly responsible for implementing the gas policy, staff within the Ministry need to be:

• Aware of the direction of the policy and the key parts of the contents; • Aware of what is required of them individually; • Persuaded of the benefits and enthused so that they work on its implementation.



10.1.2 Other Government Table 16: Stakeholders comments on Key Fiscal Changes.

S/No. Key Fiscal Changes

FIRS FMOF BOF RMAFC NNPC NIPC

1. Amendment of AGFA provisions in the PPTA

ü ü ü ü ü ü

2 Amendment of Capital Gains Tax Act in respect of Assets sale and disposal in Petroleum Sector

ü ü ü ü ü ü

3 Inclusion of Cost Control tax inversion penalty and Lower Hydrocarbon

ü ü ü ü ü ü

4 Reliance on Royalty for Govt. Take Instead of Taxes

ü ü ü ü ü ü

5 Cost Based Incentives to Production based incentives

ü ü ü ü ü ü

6 Improved Fiscal Terms for Midstream oil and Gas Investment

ü ü ü ü ü ü

7 Removing the Deductibility of Acquisition Cost under Qualifying Capital Expenditure

ü ü ü ü ü ü

8 Removing Gas Flared Penalties from Qualifying Deductions

ü ü ü ü ü ü

9 Requiring Economic Efficiency tests for Regulations in order to improve Regulatory Rule Setting

N/A N/A N/A N/A N/A N/A



10 Amendment of Industrial Development Income Tax Relief Tax

ü ü ü ü ü ü

The same applies to other parts of government, including parastatal organisations such as:

• NNPC and subsidiaries; • Existing regulatory bodies such as PPPRA, DPR etc.

10.2 External Communications

10.2.1 Communication to Stakeholders External communications will be needed to the other stakeholders in the Nigerian petroleum industry, covering:

• The general public, the Nigerian people; • International investors; • Domestic investors; • Civil society; • Donor community; • Other stakeholders.

External communications to the general public and other stakeholders will take the form largely of media presentations and interviews, seminars, workshops, newsfeeds, websites, mass media and the like.

10.2.2 Industry Involvement and Consultations The petroleum industry in Nigeria has been involved in the development of the petroleum policy, through their participation in industry fora and seminars, such as the Nigerian Chapter of the Society of Petroleum Engineers, the OPTS and the Petroleum Club. This petroleum fiscal policy therefore, while driven by and led by the government, is a joint production from the government and the petroleum industry community in Nigeria, with domestic and international industry involvement.



11 ROADMAP AND ACTION PLAN

11.1 Summary of Philosophy The philosophy of the action plan for the petroleum fiscal policy is for the government to put the legislative and commercial framework in place and then let the market develop by itself. The government will set targets for market development, monitor progress and take appropriate actions to ensure market development takes place. However, petroleum development in Nigeria is ultimately down to the private sector to deliver. A roadmap and action plan for delivering the petroleum fiscal policy is set out with different scales for the types of activity:

• Short term: Months, up to one year; • Medium term: One to two years; • Long term: Over two years.

11.2 Critical Policy Milestone There is just one critical milestone for implementation of the petroleum fiscal policy:

• Enactment of legislation.

11.3 Short-Term Activity (Up to One Year) – Enact Legislation Timescale: Months (up to one year) Scope: Institutional Enactment of petroleum fiscal legislation is targeted as a short-term activity, that is, legislation is targeted to be enacted within one year.

CONSULTATION DRAFT National Fiscal Policy250217 · 2017. 3. 1. · 9.2 2016 Petroleum (Fiscal...

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