Policing the Policy Series Volume 8 Prepared by: Temitope Adeyinka Edited by: Victoria Ibezim-Ohaeri ©April 2013

SPACES FOR CHANGE www.spacesforchange.org

This policy paper appraises the commercial and fiscal provisions

of the PIB within the context of global competitiveness, best-

practice benchmarks, commercial attractiveness and

investment sustainability.

PIB: A Review of its Fiscal Competitiveness and Investment Friendliness Policy Briefing Paper

PIB: FISCAL COMPETITIVENESS AND INVESTMENT FRIENDLINESS

1

Introduction

In July 2012, the Petroleum Industry Bill (PIB) was forwarded to the National Assembly for consideration and passage into law. The PIB provides a legal, fiscal and regulatory framework for the Nigerian petroleum industry. It repealed about 16 pieces of petroleum legislation in Nigeria such as the Petroleum Act, Associated Gas Re-injection Act, Petroleum Profits Tax (PPT) Act, Deep Offshore and Inland Basin Production Sharing Contracts (PSC) Act and other extant laws governing the industry operations. It went further to aggregate all the laws into a single piece of comprehensive legislation. This policy paper appraises the commercial and fiscal provisions contained in the Bill within the context of global competitiveness, best-practice benchmarks, commercial attractiveness and investment sustainability. Fiscal Terms Nigeria currently runs both the concessionary and contractual petroleum fiscal systems. The concessionary terms are in form of Joint Ventures (JV) with International Oil Companies (IOCs). The contractual terms take the form of Production Sharing Contracts (PSC) and Service Contracts (SCs). The tax regime in the PIB proposes to replace the PPT with the Nigerian Hydrocarbon Tax (NHT) and amend the imposition of Companies Income Tax (CIT) on upstream companies. It also removes the Investment Tax Credit/Allowance (ITA/ITC) for PSCs and Petroleum Investment Allowance (PIA) for JVs, replacing them with production allowance. Key elements of the fiscal terms such as the fees/bonuses, royalties and the terms of PSCs are omitted in the Bill. Fees and royalties are left out to be set by ministerial regulation while the terms of PSCs are expected to be negotiated separately. The main provisions for the tax regime include the NHT which is chargeable at 50% for onshore and shallow water operations and 25% for deepwater, frontier acreages and bitumen. The CIT is chargeable at 30% of net profit. For the NHT, allowable tax deductions are similar to the current PPT but with some modifications while more expenses are disallowed for NHT deduction in the PIB than under the current PPT. Upstream gas producers that solely supply the domestic market will benefit from the incentive of a 3-year CIT holiday. The proposed capital allowance incentive removes the restriction on the total capital allowance an upstream petroleum company can claim. Another incentive in the PIB is the production allowance (PA) which replaces the ITA/ITC and PIA. The PA will replace ITA/ITC for PSCs that produce crude oil, natural gas and condensates. The PA will replace PIA for JVs that produce only natural gas; JVs that produce crude oil will not be entitled to the PA. Marginal field operators will also be entitled to PA for crude oil, natural gas and condensate production. One of the major risks petroleum investors are wary of is that of fiscal uncertainties. The omission of key items of the fiscal terms like fees/bonuses, royalties and the terms of PSCs is a potential source of fiscal uncertainty which can deter much needed investments to boost Nigeria’s declining petroleum reserves. The bases, percentages and dynamics of fees and royalties are left to the prerogative of the petroleum minister to make subsequent regulations covering those major areas. This seems antithetical to the Bill’s overarching objective to aggregate all Nigerian petroleum-related legislation, including the petroleum fiscal regimes into a single comprehensive document. Apart from creating fiscal uncertainty for investors, it will be difficult to determine future government and investor shares of petroleum revenues. Also, the cost recovery and profit oil sharing terms of the PSCs are omitted in the PIB and these are key factors of a

One of the major risks petroleum investors are wary of is that of fiscal uncertainties. The protracted delay in the passage of the PIB in the past had given rise to fiscal uncertainty in Nigeria and has led to a decline in the level of new investments to boost petroleum reserves.

PIB: FISCAL COMPETITIVENESS AND INVESTMENT FRIENDLINESS

2

fiscal regime which are necessary in determining government share of revenues. Since 2009 when a major legislative attempt to have the Bill passed failed, the continuing delay in the passage of the PIB has put bid and licensing rounds on hold for more than five years, giving rise to fiscal uncertainty, and declining levels of new investments to boost petroleum reserves. Nigeria’s fiscal regime has historically been regressive in nature in terms of its efficiency in targeting economic profit in petroleum exploration. This means government take goes down as profitability goes up. It also means that as oil price reduces and costs increase, government take increases. To address the regressive nature of the fiscal regime, it is expected that royalties in the PIB will be both production-based and price-based and while this will translate to increased government take; it will also mean increased royalties payment for the producers without taking into factor the effect of increasing/high costs. In terms of global competitiveness, Nigeria’s current fiscal terms have one of the highest levels of government take (receipts from royalties, taxes, bonuses, production or profit sharing, and government participation). A report by Wood Mackenzie1 shows that Nigeria’s tax share from JVs in the past decade has averaged 83% - 90% (excluding NNPC’s equity oil) of pre-take revenue2 annually (and if NNPC’s equity oil is included, government’s take averaged 92% - 97% of pre-take revenue). The Wood Mackenzie report also showed government’s average tax share from PSCs has been about 66% (without NNPC’s profit oil). Another comparison3 of government take among 44 oil producing countries ranks Nigeria’s share of oil revenue as follows: the JVs in the 83rd percentile and PSCs (especially deepwater) in the 74th percentile. The average government take for Nigeria was estimated at 87% - 89% for JVs and 81% - 83% for PSCs (including NNPC’s profit oil). The world average government take is about 64-70%. Ireland has a very low government take, at about 27% and Iran a very high one, at 95%. Most government takes are between 40% and 85%. Comparing the fiscal provisions of the new PIB with the current fiscal terms, Wood Mackenzie in an independent assessment of the economic impact of the new terms concluded that taxation is slightly increased for oil production and is increased in absolute terms by about 50% - 55% for gas production. Analyses from the assessment show that the economic value of currently producing deepwater fields will be lowered and the viability of new deepwater projects will be threatened by the new PIB fiscal terms. They also show that gas projects which currently struggle to break-even due to low gas prices will experience the biggest increases in government take, and as a result, the government’s aim of promoting gas investments will be undermined. They estimate that around 10 trillion cubic feet of discovered deepwater gas would remain undeveloped. The position of oil operators on the fiscal terms of the PIB also agrees with the results of economic impact analyses by industry analysts. Oil majors like ExxonMobil Nigeria1 contend that Nigeria already has one of the world’s most onerous fiscal terms with a government take of 86% and it is set to increase to over 90% under the PIB. The weight of the evidence emerging from an independent analysis it (Exxon Mobil) conducted on the Bill’s fiscal terms reveals that the new fiscal regime will render most gas projects and new deepwater projects uneconomic. Further economic forecasts show that there will be a drop of 100% in deepwater projects, 87% in JV gas and 23% in JV oil. On the other hand, small and mid-sized indigenous oil operators contend2 that the new PIB does not provide local companies opportunities for growth, as investment in gas projects is threatened under the proposed terms. While the Bill’s objective to establish a progressive fiscal framework that encourages investment and increases revenues to the government is noble, the emphasis on increasing government revenue must be balanced with incentives to boost investment on new discoveries.

1 Statement made by Mark Ward, Exxon Mobil Managing Director at a stakeholders’ forum in Lagos

2 Seye Fadahunsi of Pillar Oil also stated the position of small and mid-sized indigenous oil operators at the forum

Nigeria already has one of the world’s most onerous fiscal terms with a government take of 86% and it is set to increase to over 90% under the PIB. - IOCs

PIB: FISCAL COMPETITIVENESS AND INVESTMENT FRIENDLINESS

3

Overall, the fiscal terms contained in the new PIB do not provide economic incentives for the development of gas and deepwater projects. That does not mean that there are no incentives in other areas such as production allowance to encourage further exploration in already producing areas; 3 year tax holiday for gas projects aimed at the domestic market and capital allowance to encourage further investment. However, there are no specific incentives to encourage economic development of new gas projects, small and marginal fields and deepwater areas. Nigerian Content One of the main objectives of the PIB is to promote the development of local content in the petroleum industry. In this regard, the Nigerian Content Development and Monitoring Board shall continue to remain as a parastatal under the petroleum ministry. The inclusion of approved Nigerian content plan is a major condition for the approval of field development plans and work programmes. This will help to grow the local technical capacity in the petroleum industry, increase the volume of locally executed projects and enhance employment generation by way of increased local petroleum companies. However, some of the drawbacks are that local content can lead to higher costs and project delays in the short term. It is therefore imperative that the timeline of local content drive is realistically and gradually scaled. An overly aggressive local content drive can lead to the sort of recent situation in Brazil where project delays and high costs are

having negative impacts on budgets and project timelines. Gas Issues and Domestic Obligation Promoting domestic gas utilization and supporting the gas master plan are among the Bill’s core objectives. Gas producers are expected to allocate a portion of their gas production to the domestic market. UPI will determine the domestic demand of gas and thereafter impose the domestic gas supply obligation on all gas leases. The domestic gas supply obligation (DGSO) seems to make no distinction between gas fields to be involved and the ratio of production to be allocated to the domestic market. This can be a potential source of problem since gas prices in the domestic market in Nigeria are very low and the domestic price may not support an economic production of gas from small/marginal fields or high cost deepwater field. There should be an optimized strategy to incentivize deepwater fields to supply the domestic market and possibly exclude small/marginal fields from the DGSO. In countries such as Egypt and Indonesia, a combination of domestic gas obligation and low domestic gas price have resulted in lower exploration activity and had negative effect on investment for further gas development. An optimized domestic gas supply strategy will ensure adequate supply to the domestic gas market as well as continuous investment in gas exploration and development. With respect to gas flaring, there are no details on penalty fees and no specific timelines for a total flare-out date in the PIB. The penalty fees and flare-out dates are to be determined by the minister from time to time by regulation. The PIB also makes provision for specific circumstances under which gas flaring can be temporarily permitted for a limited number of days, subject to extension and approved by the minister.

One of the main objectives of the PIB is to promote the development of Nigerian content in the petroleum industry. A major condition in the PIB for the approval of field development plans and work programmes is the inclusion of approved Nigerian content plan. This will help to grow the local technical capacity in the petroleum industry, increase the volume of locally executed projects and enhance employment generation by way of increased local petroleum related companies.

PIB: FISCAL COMPETITIVENESS AND INVESTMENT FRIENDLINESS

4

Licenses and Leases The administration of all petroleum acreages for the purposes of exploration, development and production shall lie with the Upstream Petroleum Inspectorate (UPI). Therefore all upstream petroleum leases and licenses will be issued by the UPI subject to the written consent of the minister. A Petroleum Exploration Licence (PEL) will be awarded for the non-exclusive right to carry out petroleum exploration. It will be valid for 3 years and will not include any right to win, store, transport, export or treat any discovered petroleum. A Petroleum Prospecting Licence (PPL) will be awarded for the exclusive right to carry out petroleum exploration operations and to carry away and dispose of any crude, natural gas or bitumen discovered during prospecting operations. It will be valid for 5 years for onshore and shallow water acreages and 8 years for deepwater and frontier acreages. Beyond the standard validity period, an extension of 2 years will be granted for appraisal and a retention period of 10 years will be granted in case of significant gas discovery. Where there is a commercial discovery, the maximum appraisal period or significant discovery retention period will be extended until the process leading to the grant of a lease. There are provisions for revocation if the licensee does not fulfil the terms of the PPL. There are also provisions for relinquishment if there is no discovery, if the discovery is of no interest to the licensee or if the license expires. The Petroleum Mining Lease (PML) will give a lessee the exclusive rights to carry out upstream petroleum operations. Upstream petroleum operations include activities to; develop and produce petroleum deposits as well as restart or continue petroleum production. A PML will also contain the right to explore and prospect deeper formations in the lease area. A PML will be granted to the licensee of a PPL with commercial petroleum discovery. A PML will also be granted on a field with suspended wells or commercial production if the corresponding PML has been revoked or has expired. The PML will be valid for 20 years if derived from a PPL where commercial discovery has been declared. If the PML is granted on an unexpired PPL, the duration of the lease will be an aggregate of the mandatory 20 years and the balance of the unexpired term of the PPL. For onshore and shallow water acreages, the total duration of the lease will be 27 years from the date of the award of the related PPL. For deepwater and frontier acreages, the total duration of the lease will be 30 years from the date of the award of the related PPL. There are provisions for revocation if the licensee does not fulfil the terms of the PML. Upon expiration, a PML with commercial production will be entitled to a renewal of 10 years and at the expiration of such renewal, the acreage will be relinquished. After 10 years of granting a PML, parts of the acreage which are not in commercial production or which do not have commitments for development will be relinquished. Current marginal field operators will be entitled to apply for PMLs. Current OPLs and OMLs including the JVs and PSCs will continue to be valid until their expiration dates. However, current license/lease holders will have the option of either relinquishing or converting to PPL, parts of their acreages which are not being explored, proposed as discovery, developed or produced. All acreages relinquished by current license/lease holders of OPLs and OMLs will be converted by the UPI into new PPL and PML as the case may be. The award of petroleum licences and leases will be by open, transparent and competitive bidding process conducted by the UPI and subject to the written consent of the minister. The PIB clearly makes no provision for discretionary award of petroleum licenses/leases. However it also makes an exception for the president to have the power to grant licenses and leases.

PIB: FISCAL COMPETITIVENESS AND INVESTMENT FRIENDLINESS

5

The upstream licensing regime of the PIB is clear on the provisions regarding expected work commitments, validity periods, revocation and relinquishment terms, government participation, license/lease award and assignment process and progression from exploration to production. A major source of potential conflict is the president’s discretionary power to award licenses/leases. This is inconsistent with the PIB’s objective to promote transparency and competitiveness, more so when there are no stipulated guidelines or peculiar circumstances under which the president’s discretionary power will be exercised. Perception is growing that such discretionary awards only serve to grease and sustain political patronage. That provision should accordingly, be expunged.

Conclusion

This policy paper argues that there are obvious gaps in the PIB that may potentially undermine its fiscal competitiveness, investment security, transparency and accountability. Subjecting these contentious areas to thorough legislative scrutiny and engagement are critical to the development of a workable and globally competitive oil regime. It is hoped that the recommendations proffered in this paper will contribute to the passage of a bill that ensures an efficient and independent regulatory environment, promotes transparency and maximizes petroleum revenues for the government while ensuring sustained investments to meet present and future energy needs.

1 Global Competitiveness of Nigeria’s Upstream Fiscal Terms, Wood Mackenzie 2009

2 Pre-take Revenue = Total Revenue - Costs

3 Daniel Johnston, Journal of World Energy Law and Business, 2008

About Spaces for Change (S4C)

Established in May 2011, Spaces for Change (S4C) is a non-profit organization working to infuse human rights into social and economic governance processes in Nigeria. Mainly through research, policy analysis, community action and public advocacy, the organization works to increase public participation in social and economic development, and also help public authorities and corporate entities to put a human rights approach at the heart of their decisionmaking. Address: 3 Oduyemi Street, 1st Floor, Opposite Ikeja Local Government Secretariat, Anifowoshe, Ikeja, Lagos State, Nigeria

Email: info@spacesforchange.org ;

spacesforchange.s4c@gmail.com

Telephone: +234-1-8921097; +234-81-84339156

Website: www.spacesforchange.org

Blog: www.spacesforchange.blogspot.com

Within the context of focus of this policy paper, there are obvious gaps in the PIB in terms of fiscal competitiveness, stability and certainty, institutional and regulatory framework, transparency and accountability. It is expected that some of these areas of controversies will be resolved during the process of legislative debates so that a workable and globally competitive petroleum bill will be passed soon.