NATURAL GAS EXPLORATION AND PRODUCTION IN NIGERIA AND ...

NATURAL GAS EXPLORATION AND PRODUCTION IN NIGERIA AND MOZAMBIQUE: LEGAL AND CONTRACTUAL ISSUES

By

Tade Oyewunmi1

An older version of this paper was published as part of the OGEL Special on "Natural Gas Developments: An International and Challenging Legal Framework": OGEL 1 (2015), www.ogel.org URL: www.ogel.org/article.asp?key=3524

1

Tade is an energy lawyer and doctoral researcher at the Centre for Climate Change, Energy and Environmental Law, University of Eastern Finland (Joensuu, Finland) and a Senior Counsel at the law firm of Adepetun Caxton-Martins Agbor & Segun, Lagos, Nigeria. Email: [email protected] or [email protected].

Tade Oyewunmi- Gas Exploration and Production in Nigeria & Mozambique

1. Introduction Over the past decade, there has been a continued increase in the demand and share of natural gas in the global energy mix, which ordinarily signifies good news for investors and stakeholders in gas exploration and production.2 While increase in supply from North America, Norway, Saudi Arabia and Qatar, for example, reflected new field development trends, the outlook in some countries, especially in sub-Saharan Africa, shows a struggle to increase production largely due to some upstream commercial, legal and regulatory challenges affecting the efficient development of new fields.3 These challenges are unique and sometimes similar, and they include pricing and commercialization framework, legal and regulatory reforms and uncertainties, transparency and coherence in State intervention and participation, balancing exports vs. domestic supply preferences, and rent-seeking private investor disposition. The global gas demand is expected to rise by 15.6% between 2012 and 2018, an increase which is equivalent to the current gas production in the Middle East or 1.7 times that of the current global liquefied natural gas (LNG) trade.4 As a result of the proven gas reserves profile of subSahara African countries like Nigeria and recent significant discoveries in Mozambique, the region is expected to play a key role in meeting the future global gas demand. Recently, more investors and international oil companies (IOCs) have showed considerable interest in developments in new East Africa plays, especially Mozambique, while host states like Nigeria continues to hold the largest proven gas reserves of about 187 trillion cubic feet (Tcf).5 Exploration and production contracts (“Upstream Contracts”) constitutes a key part in the commercial and regulatory framework governing the rights, interests, and operations of investors and host countries in the exploration and production (E & P) of oil and gas. This paper seeks to discuss some legal and contractual issues encountered in relation to natural gas developments and Upstream Contracts while focusing on Nigeria and Mozambique. Although Nigeria can be regarded has having more advanced upstream petroleum operations pedigree compared to Mozambique, since commercial operations in Nigeria effectively commenced in 1956; contractual arrangements and regulation in relation to exploration and production of gas appears to be relatively more coherent (although largely untested) in Mozambique. Especially, following the recent commercial gas discoveries in the Pande/Temane and Rovuma basins of Mozambique.6

International Energy Agency (IEA), 'Natural Gas Information 2013' IEA Publications (Paris, France ), 1 – 655 at 1.3 IEA (n1) ibid 4 International Energy Agency (IEA), 'Medium-Term Gas Market Report 2013' IEA Publications (Market Trends and Projections to 2018, Paris, France) 1 – 186 at 12. 5 Tade Oyewunmi, 'Examining the legal and regulatory framework for domestic gas utilization and power generation in Nigeria' (2014) 7(6) The Journal of World Energy Law & Business, pp. 538 – 557 at 540 – 542. 6 ICF International, 'The Future of Natural Gas in Mozambique: Towards a Gas Master Plan' ICF International (Report no. 80683 Submitted to: The World Bank and Government of Mozambique Steering Committee), 1 – 76; Petroleum Law of Mozambique Law No. 21/2014 (also the new Hydrocarbons Tax Law No. 27/2014 and Law No. 25/2014 of Mozambique); Mozambique’s Model Exploration and Production Concession Contract 2010 adopted following the 4th licensing round in 2010. 2 3

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2. Contractual and legal issues for Natural Gas Exploration and Production The property in and ownership of oil and gas resources in the onshore and offshore territory of host countries (apart from the US which has a system of private ownership) typically resides in the state and managed by the Government.7 As a result of the high-risk profile and capital intensive nature of upstream petroleum operations, the Government(s) engage private investors and companies (including IOCs and local independents) for their financial and technical capabilities and the need to spread or share attendant risks. The relationship between the host state and the companies are primarily guided by law, regulations, and contracts which forms part of the state’s public and administrative law, most of which is increasingly considered as part of international oil and gas law.8 The host countries will ordinarily seek to maximize revenue and socio-economic (or in some cases political) benefits from petroleum E&P operations, while the private investors mainly seek to maximize profits and returns on investments, and also efficiently isolate or mitigate perceived risks.9 These divergent interests often creates two major conflicts, which are- (i) the allocation of risks and balancing of divergent interests between the private investor and host country; and (ii) adequacy of incentives for the private companies to help in meeting the host countries objectives. It is noted that the technical and financial capacities of the State; the level of competition amongst IOCs and other companies for E & P rights; the size of risks at each stage of operations and relevant constitutional provisions usually determine the type of contractual regime under which the host state engages these companies.10 Compared to ‘oil’, natural gas has several distinct characteristics such as- (i) its physical properties (gas being lower density, but higher volatility), burning qualities and thermal efficiency (gas is cleaner and relatively more efficient or power generation); and (ii) the relative marketability, since gas requires large, fixed ex ante investments from the exploration, production, processing, transportation and distribution stages, including designated buyers or markets, while crude oil is freely traded internationally on the open market.11 Furthermore, largely due to the relative preference for oil and liquid hydrocarbons, countries with substantial oil and gas reserves and mature petroleum industry have traditionally developed a single suite of regulations and 7

Section 44(3) Constitution of the Federal Republic of Nigeria, 1999; Constitution of the Republic of Mozambique 2004; Article 18, Petroleum Law of Mozambique Law 21/2014; See also Jubilee Easo (Ashurst LLP), 'Licences, Concessions, Production Sharing Agreements and Service Contracts' in Geoffrey Picton-Turbervill (ed), Oil and Gas: A Practical Handbook, (First edn Globe Business Publishing, London 2009), pp. 27 – 40 at 27. 8 Kim Talus, Scott Looper and Steven Otillar, 'Lex Petrolea and the internationalization of petroleum agreements: focus on Host Government Contracts' (2012) 5(3) The Journal of World Energy Law & Business, 181 – 193; 9 Dr. Eduardo Pereira and Prof. Kim Talus, ‘Upstream Regulation: an Introduction’ in Dr. Eduardo Pereira and Prof. Kim Talus (eds.), Upstream Law and Regulation: A Global Guide (Globe Law and Business, London, UK 2013), pp. 7 – 13 at pg. 8. 10 Jubilee Easo (n7) at 28; Talus et al (n8) at 182 – 183; 11 Steven J Malecek, 'A legal framework for gas development: How can host governments strike a balance between investment and competition?' (2001) 5 CAR (CEPMLP Annual Review), available.

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Upstream Contracts dealing with both oil and gas. In such contexts, gas is usually treated as a byproduct at best or at worst as a nuisance to be flared.12 Recently, some countries with more significant gas reserves have paid attention to upstream regulation and commercialisation of gas, especially associated gas, as opposed to non-associated gas fields.13 There are complexities and challenges in marketing and financing gas development projects such as the reliability and maturity of the domestic gas market, proximity to the three main international markets and security of demand from those markets.14 As a result of the preceding issues, most host government contracts are traditionally more oriented toward oil exploration and production rather than gas. Gas related issues which would ordinarily include, commercialisation, title to gas during and after exploration phase, duration of E & P rights, transportation, processing and sales, domestic market obligations and supply, often had little or no attention in these contracts and regulatory framework. Host government contracts or Upstream Contracts can be classified as (i) Licenses and Concessions; (ii) Production Sharing Contract (PSC); and (iii) Risk Service Contract and Pure Service Contract.15 The following sub-headings will briefly outline the unique features of these Upstream Contracts2.1. Licenses and Concessions Earlier forms of concessions were essentially an arrangement in which the state transfers absolute control and ownership of land and hydrocarbons in a defined area within its territorial jurisdiction to a private oil company (usually an IOC) for a lengthy duration, such as 70 – 90 years. Furthermore, the IOC obtains title to all hydrocarbons in situ and produced, while paying some consideration and rent to the state. The IOCs bore all attendant risks and rewards under the old concession arrangements. Hence the rewards were lopsided in favor of the IOC’s, including overall benefits, control of E & P operations and ownership of attendant rights and interests in the hydrocarbons.16

12

Ernest E. Smith, John S. Dzienkowski, Owen L. Anderson, John S. Lowe, Bruce M. Kramer & Jacqueline L. Weaver, ‘International Transactions in Natural Gas (Ch.13)’ in Ernest E. Smith et al (eds), International Petroleum Transactions (3rd edition RMMLF, 2010) pp. 1022 – 1101; Hakim Darbouche, 'Issues in the pricing of domestic and internationally-traded gas in MENA and sub-Saharan Africa' the Oxford Institute for Energy Studies (Working Paper, Oxford, 2012), pp. 1 – 37 at 6 – 7 13 Hakim Darbouche (Ibid). 14 Yinka Omorogbe, Oil and Gas Law in Nigeria, Simplified Series (Malthouse Press, Lagos, Nigeria 2003), pg. 1 – 209 at pp. 55 – 56; Raymond Li, Roselyne Joyeux, and Ronald D. Ripple, 'International Natural Gas Market Integration' (2014) 35(4), The IAEE Energy Journal, pp. 159 – 179; Steven J Malecek (n11); Hakim Darbouche (n12) at 11. 15 Jubilee Easo (n7); Talus et al (n8); Pereira and Talus (n9) at 11 – 13; Yinka Omorogbe (n14) at 38 – 54; Egheosa Onaiwu, 'How Do Fluctuating Oil Prices Affect Government Take Under Nigeria's PSCs?' (2008/09) 13 CAR (CEPMLP Annual Review), pg. 1 – 23 at 2 – 4, available at . 16 Jubilee Easo (n7) at 33;

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Following international events such as the UN Declaration of Permanent Sovereignty over Natural Resources for host countries in 1962,17 the major petroleum producing countries developed more legal and regulatory instruments to take ownership of their resources and maximize state benefits from E & P activities.18 Thus, newer forms of concessions such as Licenses or the Oil Mining Lease (OML) under the Nigerian Petroleum Act, 1969 (“Petroleum Act”) were introduced.19 In this regard, the state maintains ownership and sovereignty over its land territory and mineral resources in situ, while it grants the licensee or lessee the exclusive right to carry out petroleum operations in a defined area and within a definite period, usually 20 – 30 years. It also confers on the licensee or lessee a non-possessory interest in the produced hydrocarbons or a profit-à-prendre (“right of taking”), which gives the licensee or lessee the exclusive right to take and dispose-off produced hydrocarbon at the well head. The Nigerian OML confers on the holder the exclusive right within the leased area to conduct exploration and prospecting operations and to win, get, work, store, carry away, transport, export or otherwise treat petroleum (including natural gas) discovered in or under the leased area for a maximum duration of 20 years subject to renewals.20 Although, ten years after the grant of an OML, one-half of the area of the lease shall be relinquished.21 The relinquished areas may, of course, include any undeveloped gas fields and reservoirs. By entering into a Joint Venture Agreement (JVA) and Joint Operating Agreement (JOA), the state may participate in the E & P operations and share with the IOC the attendant risks and benefits based on agreed participating interests.22 The JVA often comprises of the Participation Agreement which defines the relationship and participatory rights of parties and the JOA which defines the legal and operational relationship of the joint-venturers by providing for issues such as the operator of the lease or concession, the operating committee, work programme and budget, disposition of production, relinquishment, decommissioning, allocation of costs and profit hydrocarbon, transfer of participating interests and rights etc.23 The Host State participates in E & P operations usually through the national oil company (NOC) and holds participating interests in the concession or lease. As a result, it bears part of the risks (especially financial) and rewards of the operations to the extent of its participating interests under the JVA/JOA. The state also earns taxes, royalties, and rents from the concession. United Nations, ‘Permanent Sovereignty over Natural Resources General Assembly resolution 1803 (XVII) New York, 14 December 1962’ available at < http://legal.un.org/avl/ha/ga_1803/ga_1803.html> 18 Egheosa Onaiwu (n15) at 4. 19 CAP P10, Laws of the Federation of Nigeria 2004. 20 Para. 11, First Schedule, Petroleum Act. 21 Para. 12, First Schedule, Petroleum Act. 22 See. Omorogbe (n14) at pp. 38 – 40; Jubilee Easo (n7) at 28. According to the AIPN’s Model International Joint Operating Agreement, 2012 “Participating Interest” means each party’s undivided share (expressed as a percentage of the total shares of all Parties) in the rights, interests, obligations, and liabilities of the Parties to the JOA. 23 AIPN’s Model International Joint Operating Agreement 2012 available at ; also Charles Golvola (Chadbourne & Park LLP), 'Upstream Joint Ventures- Bidding and Operating Agreements' in Geoffrey Picton-Turbervill (ed), Oil and Gas: A Practical Handbook, (First edn Globe Business Publishing, London 2009), pp. 41 – 55. 17

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2.1.1. Production Sharing Contract In the strictest sense, while a concession or license is a permission to produce, take-away and dispose-off petroleum, a PSC is essentially an agreement in which the state appoints the IOC or private independent as contractor to carry out E & P operations and parties agree to share produced petroleum from the defined contract area in pre-determined percentages.24 Ownership of petroleum produced and in situ as well as produced volumes remains vested in the state. Upon production, however, the Contractor is entitled to a share of volumes (to recover costs (i.e. cost oil) subject to any agreed cost-recovery ceilings) and the pre-determined share of profit oil, after royalty (oil) or income tax is deducted and paid to the state or NOC as the case may be.25 The contractor bears all the exploration risks and usually in charge of operations and management of contract area unless the state party agrees to participate in the venture directly. If no oil is found the contractor receives no compensation. This is perhaps the reason why PSCs are preferred by most Host States where probable reserves are high, and the costs are relatively low or mediumlevel, while the licenses or concessions are often adopted where reserves are relatively low, and production costs are high.26 Furthermore, under PSC arrangement, the host state avoids the burden of ‘cash call obligations’ that arises as a result of holding participating interests under a JVA/JOA framework. Depending on agreement between parties, PSCs are usually designed to have a lifespan of 30 years i.e. ten years for exploration and 20years for production. Generally, the duration of the exploration and production period and the time frame for the announcement of a commercial discovery, completion of utilisation project feasibility and which party is responsible for marketing and commercializing gas discoveries (if any) are key parameters in the development of either associated or non-associated gas fields, which should be unequivocally regulated by law and/or contract.27 Likewise, the PSC may also be negotiated to cover subjects like health and safety, decommissioning, environmental protection, taxation and where required by law subjects like domestic gas supply obligation. Like the Concession or JVA, the PSC can be used to cover perceived gaps in the applicable legal framework, especially when such legal framework is not so advanced or effective.28 2.1.2. Service Contract Service Contracts for upstream exploration and production are either Risk Service Contract (RSC) or a Pure Service Contract. Under an RSC, the contractor provides the bears the entire E &

Pereira and Talus (n9) at 11 – 13; Tade Oyewunmi, 'Stabilisation and Renegotiation Clauses in Production Sharing Contracts: Examining the Problems and Key Issues' (2011) 9(6) OGEL Journal, pp. 1 – 26 at 5 – 6. 25 Oyewunmi (n24) at 5 – 6; Omorogbe (n10) at 41. 26 Egheosa Onaiwu (n15) at 4; A. Al-Attar and O. Alomair, ‘Evaluation of Upstream Petroleum Agreements and Exploration and Production Costs’, OPEC Review, (2005) 29(4), pp. 243 – 266. 27 Steven J Malecek (n11) ibid. 28 Jubilee Easo (n7) at 35. 24

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P capital and investment risk, while the state remains the owner or the acreage and hydrocarbon produced and in situ. Where the contractor fails to make a commercial discovery, the contract is terminated, with no obligations on both parties and where there is a commercial discovery, the contractor is paid in cash or kind and also entitled to recoup expenses made.29 On the other hand, the Pure Service Contract is essentially a contract under which the capital and investment risks are borne primarily by the state, while the contractor is paid a flat fee for services and work carried out towards E & P operations. In this regard, the contractor is merely a service provider working under the state’s supervision and has no legal or beneficial interest in the oil and gas resources or E & P venture.30 Although most traditional Upstream Contracts can be categorized under one of the above headings, which also signifies different levels of resource ownership and control rights over oil and gas resources. These Upstream Contracts also define the relevant upstream operational work obligations, risk allocation and sharing for both the state and private company. It should be noted however that there are hybrids and crossbreeds in recent Upstream Contracts.31 For example, in some jurisdictions, there are PSC-type arrangements like profit oil and cost oil allocations inserted in JOAs and concessions on one hand or a PSC awarded and arranged with a consortium of IOCs or private oil companies who themselves have a JOA to guide their upstream operations. Furthermore, model Upstream Contracts have also been developed by some host states such as the Model Exploration and Production Concession Contract (EPCC) in Mozambique, while some states have recently resorted to using models developed by international organizations like the Association of International Petroleum Negotiators (AIPN), as a starting point in negotiations with IOCs and private oil companies.32 Specific petroleum or hydrocarbon legislation, regulations, guidelines and accepted practices help to guide and influence the content and performance of Upstream Contracts. 2.2. Natural Gas Exploration and Production in Nigeria Nigeria is the largest oil producer in Africa and was the world's fourth leading exporter of LNG as at 2012.33 Discovered non-associated gas fields were really never developed, whilst associated gas was largely flared until the late 1980’s and 90’s when the concept of penalizing

Omorogbe (n14) at 42; Jubilee Easo (n7) at 36 – 36; Pereira and Talus (n9) at 12. Omorogbe (n14) at 43; Jubilee Easo (n7) at 35 – 36; Pereira and Talus (n9) at 12. Under the Pure Service Contract, the contractor is hired to provide defined technical service to be completed during a specific period of time. The service company investment is typically limited to the value of equipment, tools, and personnel used to perform the service. In most cases, the service contractor's reimbursement is fixed by the terms of the contract with little exposure to either project performance or market factors. 31 Talus et al (n8) at 186. 32 Timothy Martin, 'Global petroleum industry model contracts revisited: Higher, faster, stronger' (2010) 3(1) JWELB, pp. 4 – 43 at 7 - 8. 33 U.S. Energy Information Administration (EIA), 'Oil and Natural Gas in Sub-Saharan Africa' U.S. Energy Information Administration () 1 - 25 accessed 12/08/2014; U.S. EIA, 'Report on Nigeria, December 2013' accessed 12/08/2014 29 30

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flaring of associated gas was introduced34 and much later when gas monetization projects like the Nigerian Liquefied Natural Gas (NLNG) project,35 Oso Condensate Project, Escravos Gas Project and West African Gas Pipeline (WAGP) Project were developed.36 Until 1992/1993, almost all of Nigeria’s upstream operations were carried out under the JVA/JOA arrangement between Nigerian National Petroleum Corporation (NNPC) and IOCs or other Nigerian-owned or foreign independents.37 For example, through its principal subsidiary in Nigeria, Chevron operates and holds a 40% percent participating interest in 13 concessions under a JVA/JOA arrangement with the NNPC.38 Other major JVAs includes the Shell Petroleum Development Company of Nigeria Limited (SPDC)/NNPC JVA39 and Mobil Producing Nigeria/NNPC JVA.40 Following the 1992/93 and 2005 bid rounds, the Federal Government introduced PSCs, mainly as a means of reducing its exposure to E & P financing risks and difficulties in meeting up with cash call obligations under the JVA/JOAs. The PSCs were awarded in relation to the more capital intensive shallow, and deep offshore acreages which were largely under-explored at the time.41 This move apparently paid off since a greater portion of Nigeria’s current petroleum production comes from the offshore and deep-offshore areas covered in such arrangements. The legal and regulatory framework for upstream petroleum operations are primarily stipulated in the Petroleum Act and the Petroleum (Drilling and Production) Regulations 1969 (the “Regulations”), whilst petroleum operations under PSCs in the deep offshore, inland basins and shallow waters are regulated by the Deep Offshore and Inland Basin Production Sharing Contracts Decree No. 9 of 1999 as amended (“PSC Law”). Notably, the Petroleum Profits Tax

34

Oyewunmi (n5) at 543. Backed by a project-specific Nigeria LNG (Fiscal Incentives, Guarantees and Assurances) Act 1990 which sought to guarantee fiscal incentives and investment protection, including tax holidays and waivers. 36 Omorogbe (n14) at 58 – 61. The current domestic gas pipeline infrastructure comprises mainly of two unintegrated pipeline networks of approximately 1,100 km: The Alakiri-Obigbo–Ikot Abasi Pipeline (the Eastern Network), and the Escravos–Lagos Pipeline System (ELPS), (the Western Network) and dedicated pipeline infrastructure owned by the Nigerian Liquefied Natural Gas Company (NLNG), the NNPC/SPDC/Total JV and the Chevron/NNPC JV. 37 Onaiwu (n15) ibid. 38 Chevron’s Nigeria Business Portfolio (Updated: May 2014) available at (accessed 04/01/2015). 39 The Shell operated JV accounts for more than 40% of Nigeria’s total oil production from about eighty fields. The joint venture is composed of NNPC (55%), Shell (30%), Elf (10%) and Agip (5%). The IOC’s in this JV have in the last couple of years divested their 45% stake in several concessions to some Nigerian independents, see Rolake Akinkugbe, ‘IOC Divestments in Nigeria: Opportunities, Challenges and Outlook 1’, Nigeria Development & Finance Forum Policy Dialogue, 2014, available at (accessed 11/11/2014). 40 An ExxonMobil operated JVA with an NNPC (60%) and Mobil (40%) participating interest ratio. Other IOC/NNPC JVs are NNPC (60%)/Agip (20%)/Phillips Petroleum (20%); NNPC (60%)/Elf (40%); NNPC (60%), Texaco (20%) and Chevron (20%). See NNPC, ‘Joint Venture Operations’ at accessed 04/01/2015. 41 Toyin Akinosho, ‘Nigeria: Deepwater PSC Incentive Turns On Its Head’, African Oil and Gas Report, 30 December, 2013, available at . Currently, about 95% of Nigerian upstream petroleum operations is carried out under PSCs and the JVa/JOAs, while Service Contracts, sole risk contracts and marginal field licences constitutes about 5% collectively. 35

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Act (PPTA) 1959 (now CAP P13, 2004) provides for the applicable fiscal regime for upstream activities. 2.2.1. The Nigerian Petroleum Act and Regulations The Petroleum Act provides that an OML may be granted by the Minister of Petroleum (Minister) only to the holder of an oil prospecting licence (OPL)42 who has: (a) satisfied all the conditions imposed on the licence and (b) discovered oil in commercial quantities.43 In a literal sense, the Petroleum Act fails to highlight the relevance of gas discoveries towards the grant of OMLs. It however stipulates inter alia that the Minister may in the public interest impose special terms regarding any natural gas discovered by a licensee or lessee dealing with: (i) the Federal Government’s right to take natural gas produced with crude oil by the licensee or lessee free of cost at the flare or at an agreed cost and without payment of royalty; (ii) the obligation of the licensee or lessee to obtain the approval of the Federal Government as to the price at which natural gas produced by the licensee or lessee (which is not taken by the Federal Government) is sold; and (iii) a requirement for the payment of royalty on natural gas produced and sold by the licensee or lessee.44 The Regulations, on the other hand, provides that a licensee or Lessee ‘may’ submit a feasibility study program or proposal for the utilization of associated or non-associated gas within five years of commencement of crude oil production.45 By and large, the above provisions have over the years, led to an upstream petroleum operational paradigm in which the exploitation of gas is not prioritized. Likewise, the licensees and lessees are often concerned about government-determined prices for domestic supplies which are in most cases lower than the fair market prices, to the extent that the regulated or statedetermined prices are mostly fixed in furtherance of social and political considerations.46 The government, on the other hand, has been burdened with the task of regulation through the Minister’s office, the Department of Petroleum Resources (DPR) and NNPC on one hand, and funding the participation of NNPC mostly under the JVA/JOA and PSCs on the other hand.47 Under a JVA/JOA, the inability of the state to efficiently fund NNPC’s cash call obligations and participating interests also affects the feasibility of gas development projects.48 This is perhaps a

42

An OPL is granted pursuant to Section 2, Petroleum Act, and the holder shall have the exclusive right to explore and prospect for petroleum within the area of his licence for a maximum duration 5 years (including any periods of renewal). 43 Para. 8, First Schedule, Petroleum Act. 44 Para. 35, First Schedule, Petroleum Act. 45 Para 43, Petroleum (Drilling and Production) Regulations, 1969. 46 Oyewunmi (n5) at 546 – 547. However, from 2000 onwards, countries such as Saudi Arabia, Iraq, Peru and Venezuela have entered into Upstream Contracts primarily dedicated to gas exploration and production. The surging demand for energy and gas-fired electricity following the innovation of more efficient generation systems like Combined Heat and Power (CHP) or Combined-Cycle Power Plants (CCPP); and specialized processing and transport vehicles like LNG tankers and liquefaction units, gas processing and pipeline technologies was key in the drive for more utilisation of gas. See Smith et al, (n12) ibid at 1022 – 1030. 47 Oyewunmi (n5) at 546 – 547. 48 Akinosho (n41) supra.

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major reason why the anti-gas flaring penalties against lessees and operators (who are also partners with NNPC) has not been effective because the regulator often finds itself as the regulated or in a commercial partnership with the regulated.49 Another factor in determining the commerciality and feasibility of gas projects is the duration in which the lessee has exploration and production rights over the acreage. As mentioned earlier, the duration of an OML is 20 years (subject to renewals), and the Lessee is obliged to relinquish one-half of the lease area after ten years, including any rights to take and produce gas from the relinquished area. Even though such relinquishment provision is a legitimate exercise of state control over its resources, it creates some volume-related and considerable risks from a producers’ perspective. 2.2.2. Nigerian PSCs and The PSC Law The first Nigerian PSC arrangement was between NNPC and Ashland Oil (Addax Petroleum later acquired Ashland’s interests) in 1973. It was heavily criticized locally because its fiscal terms were seen as unfavorable to the state and unfairly skewed in favor of the IOC.50 The next set of PSCs were negotiated during the 1992/93 rounds and another set following the 2005 bid rounds. The 1993 PSCs had a total duration of 30 years (10 years for exploration and 20 years for production) with provisions for relinquishing parts of the contract area. They provided for the allocation of tax oil and royalty oil to NNPC, while the contractor takes cost oil. The production split varied in different contracts and typically based on a sliding scale of cumulative production rates from the contract area. The 1993 PSCs has been criticized largely because (i) ‘government take’ paradoxically reduced even when international oil prices and profitability increased, (ii) the production split ratio was production-based, rather than the seemingly ‘pragmatic’ profit-based; (iii) the ring-fencing of PSC cost recovery and Petroleum Profits Tax (PPT) calculations considered as favouring the Contractors; (iii) applicable royalty rates and deductible expenditure for PPT in relation to PSC operations; (iv) issues regarding Capital Allowances and Investment Tax Credit applications; and (v) the management of Lifting Allocation and Scheduling which is made more complicated due to the need to calculate and determine costs, taxes, royalties and profits in kind rather than cash as agreed by parties.51 As a result of some of the contentious provisions, there has been lingering potential for renegotiations and review of terms, especially in periods of high oil prices or when the state is in dire need of extra revenue to fund its budgetary responsibilities.

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Associated Gas Reinjection Act, 1979 CAP A25 Laws of the Federation of Nigeria 2004; Associated Gas Reinjection (Continued flaring of Gas) Regulations 1984. These anti-gas flaring laws at the time in reality led to the exemption of about 86 out of 155 fields from the general ban on gas flaring, while the non-exempted fields were subject to fairly insignificant penalties which made it more economical to flare than invest in gas utilisation projects. According to the US EIA Report- Nigeria flares the second largest amount of natural gas in the world, following Russia. Natural gas flared in Nigeria accounts for 10% of the total amount flared globally. Gas flaring in Nigeria has decreased in recent years, from 575 Bcf. in 2007 to 515 Bcf in 2011. 50 Omorogbe (n14) at 49 - 50; Onaiwu (n15) at 4. 51 Oyewunmi (n24) at 10 – 11; Onaiwu (n15) at 9 – 10.

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The PSC Law provides for a 50% PPT rate (giving up to a 35% difference from other operating locations where the JV/JOA arrangements applied); a 50% 1nvestment Tax Credit on qualifying capital expenditure in relation to PSCs executed prior to 1st July 1998 and a 50% Investment Tax Allowance applicable to PSCs executed after 1st July 1998. Furthermore the PSC Law also stipulated a 10% royalty rate payable under PSCs in the Inland Basin, while a sliding scale of royalty rates based on water depth is applicable to PSCs in the deep-offshore and which due to the high-risk and capital-intensive nature of deep-offshore operations includes a 0% royalty rate for PSCs in areas in excess of 1000 meters depth (such 0% royalty was to some extent eroded by the later introduction a “production charge” effectively resulting in a royalty application or increase to operations in water depths of 801 metres and beyond).52 As stated in the PSC Law, the duration of an OPL relating to in the Deep Offshore and Inland Basin shall be determined by the Minister and shall be for a minimum period of 5 years and an aggregate period of 10 years.53 The 2005 bid rounds saw the introduction of a Model Nigerian Production Sharing Contract 2005 (“Model PSC”) which provided among other things for a cost recovery cap of 80% of available crude oil less deduction of royalty oil in any accounting period, 54 unlike previous PSCs which had no cost recovery ceiling.55 Remarkably, Clause 23 of the Model PSC deals with natural gas and hereby quoted as follows: “…23.1 If the CONTRACTOR discovers sufficient volumes of Natural Gas not associated with Crude Oil that could justify commercial development, the CONTRACTOR shall report the volume of potentially recoverable Natural Gas to the CORPORATION and shall upon CORPORATION’s request, investigate and submit proposals to the CORPORATION for the commercial development of said Natural Gas taking into consideration local strategic needs as may be identified by the CORPORATION. Any cost in respect of such proposals or investigation after the final investment decision has been achieved presented by the CONTRACTOR to the CORPORATION shall be included in operating costs for the commercialisation of the Natural Gas. 23.2 For the commercial development of Natural Gas, the CORPORATION, and CONTRACTOR, shall enter into a gas development agreement. Such agreement shall recognize that the CONTRACTOR has the right to participate in such development project, with the right to recover the costs and share in the profits. 23.3. …..the CONTRACTOR may utilize, at no cost any proportion of the produced Natural Gas required as fuel for production operations; gas recycling, gas injection, gas lift, or any other Crude Oil enhancing recovery schemes, stimulation of wells necessary for

Oyewunmi (n24) at 10 – 11. Sections 2 – 5, Deep Offshore and Inland Basin Production Sharing Contracts Act 1999. 54 Clause 9.1 (c) Nigerian Model PSC, 2005, (Source: Barrows, New York) 55 Onaiwu (n15) at 9 – 10. 52 53

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maximum Crude Oil recovery in the field discovered and developed by the CONTRACTOR…. 23.5 The sequence of establishing Discovery of commercially viable quantity of Natural Gas shall be as follows: a) CONTRACTOR shall have a period of three (3) months (unless otherwise mutually agreed by the Parties) commencing from the date of Discovery of Natural Gas to declare whether the Discovery could justify commercial development; b) CONTRACTOR shall have eighteen (18) months period commencing from the date of Discovery to appraise the Discovery; c) CONTRACTOR shall within a period of one (1) year from completion of the appraisal of a Discovery declare whether the appraised Discovery is commercial; d) CONTRACTOR shall within twenty seven (27) months from the date of the declaration of a commerciality submit a Field Development Programme to the CORPORATION for approval and thereafter diligently commence the development of the commercial Discovery….” [Emphasis mine] From the above provisions of the Model PSC, it is opined that gas development and commercialisation has received more attention and regulatory and operational priority, compared to previous upstream contractual arrangements. Unfortunately, it only applies to Post-2005 PSCs and if the PSCs eventually executed by the Corporation (i.e. NNPC) and the contractors following the bid rounds retains the provisions as it is. The attention given to gas development is perhaps understandable since by 2005 there was already a booming global gas industry and also projects like NLNG were showing much promise, including the desire of the Federal Government to increase domestic gas supply and utilization for power generation and industrialization.56

Oyewunmi (n5) ibid. See also Hakim Darbouche (n12) at 27 – 28. Surging electricity demand is one key factor responsible for the increase in natural gas demand. The most important factor in the growth in demand for gas is the growth in population and rate of development in previously non-industrialized nations. This has essentially led to increase in demand for all forms of energy. According to the International Energy Agency (IEA), ‘Natural Gas Information 2015’ (IEA Publications, 2015) there has been a general growth in demand for gas and energy in the course of the past 20 years e.g. from China and Japan. The CCPP technology uses both a gas and a steam turbine together to produce up to 50% more electricity from the same fuel than a traditional simple-cycle plant. The waste heat from the gas turbine is routed to the nearby steam turbine, which generates extra power. See GE Power Generation at accessed 01/05/2015. Likewise, the CHP or Cogeneration plants comprises of: (i) the concurrent production of electricity or mechanical power and useful thermal energy (heating and/or cooling) from a single source of energy; (ii) a type of distributed generation, which, unlike central station generation, is located at or near the point of consumption; and (iii) a suite of technologies that can use a variety of fuels to generate electricity or power at the point of use, allowing the heat that would normally be lost in the power generation process to be recovered to provide needed heating and/or cooling. See the US Department of Energy at accessed 01/05/2015. 56

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The emphasized portions of the above quotation show a clarification of how non-associated and associated gas is to be treated and utilized. Where non-associated gas discoveries are deemed sufficient for commercial development, the Corporation i.e. NNPC (who is the lessee) must be informed. However, the final investment decision on its development and whether an export oriented project like LNG or domestic supply project is developed depends on NNPC’s consideration of local strategic needs. The lack of clarity or independent (apolitical) regulation or legislation to define how or the relevant criteria NNPC must consider in evaluating such decisions may breed some arbitrariness and bureaucratic bottlenecks. In this regard, NNPC (whose chairman is the Minister) appears to be playing a dual role of both business partner with the contractors and regulator to the extent it has to approve investment decisions and development plans. Notably, clause 23.3 which seems to deal with associated gas utilization only provides that the contractor ‘may’ utilize same, which inadvertently leaves room for flaring. In other words, the contract is silent about when the contractor and NNPC decides to flare associated gas or the relevant justifications or pre-conditions that should precede such activity. It is opined that a contract based anti-gas flaring bond may be an effective option since penalties introduced by law has not be so effective. 2.2.3. The gas development and commercialisation drive- prospects and uncertainties Apart from the NLNG project, other LNG ventures that has been considered include Brass LNG and Olokola LNG (OKLNG).57 These proposed projects have been awaiting a final investment decision for several years largely due to questions about feed-in gas availability, divestments and pulling-out by IOCs who were expected to be the technical partners (e.g. ConocoPhillips pulled out of Brass LNG, while Chevron and BG pulled out from OKLNG), including the uncertainties and over-politicisation of the future investment climate in the Nigerian oil and gas industry following the protracted reforms and delayed enactment of the Petroleum Industry Bill (PIB).58 The PIB is a bill originally designed to consolidate and legalise comprehensive reforms initiated based on the Nigerian Oil and Gas Policy, 2004, including repealing obsolete extant laws and regulations on petroleum operations and taxation while replacing them with more up-to-date and coherent provisions, unbundling of NNPC and creating an independent commercially-minded NOC, implementing the Nigerian Gas Master Plan objectives such as domestic gas supply obligation, revised gas pricing and the gas infrastructure

57

Brass LNG is owned by NNPC (49%), ConocoPhillips, ENI and Total (17% each) and consists of two 5 mtpa trains (ConocoPhillips recently sold all its upstream assets/interests including interests in Brass LNG to a Nigerian company Oando), while OKLNG is a four-5.5 mtpa-train joint venture between NNPC (46.75%), Shell (19.5%), Chevron (19.5%), and BG (14.25%) based upon equity lifting by the IOC partners. NNPC has now reduced its equity stake to 40% in favour of LNG Japan, a joint-venture between Sumitomo and Sojitz. See. Hakim Darbouche (n12) at 27 – 28; Daily Independent, ‘Why FID on OKLNG, Brass LNG was delayed – NNPC boss’ ; Ifeanyi Izeze (Pointblanknews.com), ‘What Is Holding Brass LNG’s Final Investment Decision?’ 58 Oyewunmi (n4) at 553 – 554.

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blueprint, third party access regime and the establishment of autonomous regulatory agencies and institutions.59 The prevailing investment climate and the attendant low level of oil and gas exploration or de facto gas development, including the deficiencies in the regulatory regime is also affecting Nigeria’s ability to ensure adequate gas is produced and supplied to domestic power plants and also her ability to fulfill contractual commitments in international projects like the WAPG.60 The WAPG was designed to export Nigerian gas to Benin, Togo, and Ghana, with an envisaged extension into the Ivory Coast. 2.3. Natural Gas Exploration and Production in Mozambique The recent discoveries of about 32 - 65 Tcf of recoverable gas resources by Anadarko and 75 Tcf of gas in place by Eni in the prolific Rovuma basin has placed Mozambique in the spotlight as a major emerging gas province.61 In 2004, the first natural gas production in Mozambique came online from the Temane field (Inhambane province) operated by South Africa’s Sasol, with production estimated to be about 135 billion cubic feet (Bcf) in 2011.62 Currently, Mozambique’s gas-related infrastructure is largely related to Sasol’s operations and the associated 865km pipeline which supplies neighboring South Africa.63 The required experience and technical expertise to monetize the gas resources is enormous. Furthermore, the capital required for most projects and projected developments is much larger than the current GDP Mozambique, and neither does the country have the required infrastructure support base.64 Thus, the role of the private sector is critical, and the evolving legal, regulatory and commercial framework must be able to strike a sustainable and effective balance between state objectives and investors interests. 2.3.1. The legal and regulatory framework The Mozambican oil and gas industry is regulated based on the Constitution, petroleum laws and regulations; ministerial documents called Diploma Ministerial and Despachos and model ACAS, ‘The Petroleum Industry Bill 2012: a Synopsis’, August, 2012 60 Oyewunmi (n5) at 540 – 545; Hakim Darbouche (n12) at 12 and 29. The WAGP is owned by Chevron (36.9%), NNPC (24.9%), Shell (17.9%), Takoradi Power Company (16.3%), Société Togolaise de Gaz (2%), and Société BenGaz (2%). Currently, gas is being delivered on long term contracts to Ghana’s utility VRA and to Togo. Due to unreliable deliveries of gas Ghana is seriously considering alternative supply options, including from its own offshore associated gas reserves (Jubilee). 61 US EIA, 'Emerging East Africa Energy' US EIA Report 2013, accessed 12/08/2014; Anne Frühauf, 'Mozambique’s LNG revolution: A political risk outlook for the Rovuma LNG ventures' Oxford Institute for Energy Studies (Oxford, UK) OIES PAPER: NG 86, pg. 1 - 53 at 3, accessed 12/17/2014 62 Anne Frühauf (n61) ibid. 63 Anne Frühauf (Ibid). 64 Anne Frühauf (Ibid) at 6; ICF International, 'The Future of Natural Gas in Mozambique: Towards a Gas Master Plan' ICF International Report Submitted to: The World Bank and Government of Mozambique Steering Committee, 2012) 1 - 76 accessed 12/08/2014. 59

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exploration and production contracts.65 The first law of the petroleum industry was the Petroleum Activities Law of 1981 (Law 3/1981) which established an institutional framework consisting of an NOC and the State Secretariat of Coal and Hydrocarbons, a state organ integrated into the Ministry of Mines. Several agreements such as PSAs and technical evaluation agreements were executed between oil companies and the state based on this initial law. The first licensing round open to IOCs and independents was conducted in 1983. However, the Law 3/1981 was later replaced by the Petroleum Law of 2001 (Law 3/2001) following which the 2nd licensing round took place in 2005, and new model EPCCs were negotiated and executed.66 Consequently, the gas-rich Rovuma Basin was divided into 7 EPCC areas and awarded in the 2005 rounds. The Law 3/2001 and the Petroleum Operations Regulations, 2004,67 essentially served as instruments through which the government consolidated the restructuring of the petroleum industry and new policy to enable more efficiency and transparency. The restructuring led to clarification and delineating the roles of relevant institutions, regulator(s), private companies and NOC. As such, ultimate law-making power and approvals to the granting of concessions rests with the Council of Ministers, the sector’s policy and regulation is primarily administered by the Ministry of Mineral Resources (MIREM), while the Petroleum Institute (INP) regulates petroleum resources development, operations, and other E & P related activities. Furthermore, as the NOC, the Empresa Nacional de Hidrocarbonetos de Mocambique (ENH) was enabled to focus more as a commercial company and manage State investments in the industry.68 It is noted that the ENH currently has three subsidiaries which includes Companhia Mocambicana De Hidrocarbonetos SA (CMH), Companhia Mocambiicana De Gasoduto SA (CMG) and ENH Logistics SA. The CMH holds 25% participating interest in the Pande and Temane concessions operated by Sasol Petroleum, the CMG manages the State’s 25% interest in the Pande/Temane to Secunda (South Africa) gas pipeline venture, while ENH Logistics is registered to focus on the Rovuma basin projects.69 2.3.2. The Constitution, Petroleum Law, Regulation and Contracts According to Article 98 of the Constitution of the Republic of Mozambique 2004,70 all resources located in the soil and subsoil of the land territory, in the seabed of Mozambique, internal 65

Jose de Barros, 'Mozambique' in Eduardo Pereira and Kim Talus (eds.), Upstream Law and Regulation: A Global Guide (First Edition, Globe Business Publishing Ltd, London, UK 2013), pp. 103 – 134 at 105. 66 Barros (n65) at 104. 67 Mozambique Regulation of Petroleum Operations Decree No. 24/2004. 68 Barros (n65) at 108 – 110; Couto, Graça and Associates, ‘Mozambique’ in Freshfields Bruckhaus Deringer LLP Newsletter, March 2013, pg. 1 – 6, available at . The ENH was transformed in 1997 from a state corporation into a public company, with 100% of its shares held by the state. Following the Law 3/2001 and the restructuring the ENH ceased to have monopoly over E & P and lost all regulatory functions including licensing. 69 Barros (n65) ibid. 70 Translated into English by MOZLEGAL, Mozambique's Legal Resource Portal, available at

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waters and territorial sea, in the exclusive economic zone and continental shelf are the property of the State. Similarly, the State is obligated to promote knowledge, survey and develop its natural resources, and determine the conditions under which they may be utilized subject to national interests. In 2014, the government enacted a new set of laws which includes- (i) Petroleum Law no. 21/2014 (“Petroleum Law”) which replaces Law 3/2001 and applies to future petroleum contracts and grants; (ii) the Hydrocarbons Tax Law No. 27/2014 (“Tax Law”) and Law No. 25/2014, which implements the new hydrocarbons tax framework in country.71 The new Tax Law prescribes amongst other things a production sharing framework between the State and the Concessionaire for produced oil and gas.72 As such, a mechanism through which the sale of produced oil and gas is undertaken jointly by the State and the Concessionaire, while the available oil (total produced less the Hydrocarbons Production Tax) and cost oil are calculated to reach the R factor, which will determine the ratio of the profit oil owned that the State and the concessionaire will share.73 Some of the main provisions of the new legal framework and the current Model agreement relevant to gas development is identified as follows: a) State control and Participation The control of prospecting, exploration, production, transport, commercialization, refining and transformation of liquid and gas hydrocarbons and their derivatives including petrochemical and Liquid Natural Gas (LNG) and Gas for Liquids (GFL) activities resides in the State.74 In what seems as a sign of appealing to investors and corporate venture partners, the Government guarantees the adequate financing of ENH. Although, the extent and the limits such guarantee is not clarified, especially vis-à-vis other sectors of the economy and state budget. Furthermore, E & P right holders have, among other rights, the permission to build and install the necessary infrastructure and facilities for the execution of petroleum operations.75 In this regard, it is noted that there is a significant infrastructure gap in Mozambique generally. Thus, it is expected that the government will make obtaining of the requisite permits and approvals as efficient as possible. Furthermore, upstream petroleum shall be carried out via a concession contract following a public tender and simultaneous or direct negotiations. The state reserves the right to participate in such petroleum operations at any stage in accordance with the provisions of the relevant contracts. The Petroleum Law, also, recognizes that ENH is the representative and manager of the State’s commercial interest in such operations and any investor interested in the exploration of petroleum resources in Mozambique shall enter Paulo Rage, 'Mozambique’s New Hydrocarbons Framework' (December, 2014) AIPN ADVISOR, pp. 22 - 24. Paulo Rage (Ibid). 73 Paulo Rage (Ibid). 74 Article 4(1), Petroleum Law of Mozambique no. 21/2014. 75 Article 14, Petroleum Law of Mozambique no. 21/2014. 71 72

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into a partnership with ENH.76 The Government is empowered to also: a) regulate the types of concession contracts and the tender rules for the granting of rights regarding petroleum operations; b) approve the execution of EPCCs, oil pipeline or gas pipeline systems and infrastructure concession contracts; approve the access rules for oil pipelines or gas pipelines systems and infrastructure, and the methodology for setting tariffs for third party access. b) Upstream Contracts and award of E & P rights The Petroleum law creates what can be termed a contract-based concessionary system for the award and execution of E & P rights, which also forms the basis of the Model EPCC.77 The four types of concession contracts through which E & P rights are granted to investors are:78  The reconnaissance concession contract: this conveys the non-exclusive right to carry out preliminary exploration work and assessment operations in the concession contract area, for a maximum period of two years, it is non-renewable and permits the drilling of wells to a depth of 100 meters below the surface or the bottom of the sea.  Exploration and production: this is the EPCC which conveys an exclusive right to carry out petroleum exploration and production, as well as a non-exclusive right to construct and operate oil pipelines or gas pipelines systems for transportation of crude oil or natural gas, or infrastructure for liquefaction of gas produced from the concession contract area (i.e. LNG), except where access to an existing oil pipeline or gas pipeline system or other existing infrastructure is available on reasonable commercial terms. The exclusive right to petroleum exploration, under an EPCC, shall not exceed eight years.  Concession contract for the Construction and operation of oil pipeline or gas pipelines systems: this grants the right to construct and operate oil pipeline or gas pipeline systems for the purpose of transporting crude oil or natural gas, in those cases that an EPCC does not cover such operations.  Concession contract for the construction and operation of petroleum infrastructure: this grants the right to construct and operate infrastructure for Article 17 – 24, Petroleum Law of Mozambique no. 21/2014. The model EPCC used as a basis for negotiations between the state and the awardees following a licensing round is essentially a hybrid of a Concession and the PSC framework. The latest available Model EPCC of 2010. The Government is currently reviewing the terms of the 2010 Model EPCC and the new Petroleum Tax Law requires petroleum produced in Mozambique to be subject to production sharing arrangements between concessionaires and the State. According to Jose De Barros (n65), the EPCC differs from traditional PSCs since the former is governed by public administrative law and made subject to Mozambican law, while the latter are commercial agreements governed by law of contract and may be subject to foreign law. 78 Article 29 – 32, Petroleum Law of Mozambique no. 21/2014. 76 77

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petroleum operations, such as processing and conversion, which are not covered by an approved exploration and production development plan. This is a new concession contract introduced by the Petroleum Law, mainly to be awarded for construction and operation of infrastructure such as LNG plants and gas processing plants. It has been rightly pointed out that “…With respect to establishing a legal regime for LNG activities […] the new Petroleum Law can only be seen as a first step…” especially since it remains unclear the extent to which existing concessionaires such as the Anadarko and ENI-led consortia would be affected by the new Petroleum Law and Tax Law in relation to pre-approved or existing plans to build LNG facilities and gas monetization infrastructure.79 c)

Domestic market supply obligations and other commercial considerations

Article 34 of the Petroleum Law provides for the Government’s authority to permit concessionaires with oil and gas discoveries to develop projects for design, construction, and installation of related infrastructure for production, processing, liquefaction, delivery and sale of gas in the domestic market and export. This provision will hopefully give some legitimacy for the construction of new LNG facilities and other gas monetization projects, even though more detailed regulations and guidelines with regards to relevant standards, financing, third-party access and operations of such infrastructure and projects may be required in due course. This also implies that existing operators and concessionaires such as the Anadarko and ENI-led consortia, with commercial gas discoveries, can be given the right to develop and operate LNG plants without having to apply for a separate concession under the new Petroleum Law even if their upstream concession arrangements did not contemplate the development and operation of LNG facilities.80 The Petroleum Law also states that the Government shall guarantee that at least 25% of oil and gas produced is allocated to the national market. In this regard, regulating the acquisition, pricing and other matters is placed on the Government.81 The law however did not clarify from whose party’s share of oil and gas from a concession area or EPCC the 25% will be taken, especially whether and to what extent can the government take produced gas allocated to an IOC or other E&P partner for the purpose of satisfying local market requirements at government-determined prices without inducing the risk of expropriation. The relevant criteria for determining the trigger(s) of mandatory or guaranteed 25% domestic supply was also not specified. Hopefully, these gaps would be identified and

Sherman & Sterlin LLP, ‘Mozambique’s New Petroleum Legislation: Are Investors Ready to Hit the Gas?’ Project Development & Finance Client Publication, 19 September 2014, pp. 1 – 6. 80 Sherman & Sterlin LLP (Ibid). it is unclear the extent to which existing concessionaires such as the Anadarko and ENI-led consortia would be affected by the new Petroleum Law. 81 Article 35, Petroleum Law of Mozambique no. 21/2014. 79

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covered by the executed EPCC’s or regulations made by the INP. The ENH is to act has the state’s representative, and main marketer and seller of such designated products and the Government shall promote the expanded use of gas for development of the national market and industrial growth. In what appears to be a soft and permissive approach to gas flaring, Article 39 provides that flaring shall only be permitted on terms to be defined by the Government provided that all alternative methods for the disposal of the petroleum are unsafe or unacceptable for the environment. Hence, more detailed regulations and guidelines will be required regarding applicable prohibitory measures and penalties for flaring. Looking at the Nigerian experience, where anti-flaring penalties have been largely ineffective, and flaring remained extremely high until the more recent gas utilization and monetization drive, it is expected that Mozambican government will ensure the ENH’s interest in concessions are adequately financed, and gas utilization projects are fully and efficiently supported. Likewise, a contractual bond to eliminate and prevent gas flaring may also be introduced with appropriate terms and conditions. d) Gas development under the Model EPCC 2010 Notwithstanding other provisions of the Model EPCC 2010 in relation to gas utilisation and development, Article 17 specifically sets out the applicable provisions for gas under the relevant concession. It is provided that the Concessionaire shall have the right to use gas extracted from the EPCC Area for the Petroleum Operations in the EPCC Area including but not limited to power generation, pressure maintenance, and recycling operations. If the Concessionaire decides not to process and sell associated gas, the Government may offtake without any payment to the Concessionaire but at the Government’s sole risk and cost, provided that such offtake does not seriously disrupt or delay the conduct of the Petroleum Operations. Clause 17.3 provides for an appraisal program and commercial assessment process in the production and sale of non-associated natural gas. The process includes the submission of an appraisal report by the concessionaire, which will include the estimated recoverable reserves, project(s) delivery rate and pressure, quality specifications and other technical and economic factors relevant to the determination of a market for available gas. The commerciality of non-associated gas discovery to which an appraisal report has been submitted is also to be determined by the concessionaire. According the Clause 17.6, the Concessionaire shall be responsible for investigating market opportunities and marketing of non-associated gas produced from any development and production area. Furthermore, the gas volumes shall be sold as agreed by the parties to the EPCC and as approved by MIREM to the extent that the concessionaire demonstrates that the sales price and other terms represents the market value obtainable. In this regard, the fair market cost for transportation to the purchaser shall be considered, as well as the alternative uses and [19]


markets that can be developed for such gas. It noted that the provisions of the Model EPCC 2010 are based on the Law 3/2001 and not on the new Petroleum Law which explicitly places the primary responsibility for marketing and sales of produced petroleum on ENH and seeks to promote domestic use or supply as pointed out earlier. A similar clause in any future EPCC will have to reflect the paradigm shift and the leading role of the ENH in marketing and sales of gas and the objectives of boosting industrial and infrastructural growth through domestic gas supply under the new Petroleum Law. Furthermore, since there is a 25% domestic supply requirement under the new Petroleum Law, it is seems more efficient and a less acrimonious path to place the burden of marketing and sales on the NOC. Although, time will tell whether the ENH has the independence, expertise, and capacity to make such critical and knotty decisions that may affect the overall feasibility of projects and interests of private investors. 3. Key considerations in the framework for Gas development- Nigeria and Mozambique An efficient regulatory and contractual framework should enable operators and stakeholders in the industry to achieve identified objectives at the most reasonable cost, while also allowing for a sustainable balance between the profit-seeking investor and the revenue-seeking state with divergent socio-economic interests. It is also important to have legitimacy, accountability, procedural equity and transparency, and strong institutions with the appropriate expertise. 82 The regulation and commercialization of gas in Nigeria and Mozambique seems to be in a most intriguing phase, with slight similarities and unique differences. Nigeria ordinarily should have a more advanced and coherent framework, since its petroleum industry has been on the global stage since the 1960’s. The protracted Nigerian petroleum industry reforms has been an attempt to do what Mozambique has done with the Law 3/2001 and the new Petroleum Law in terms of giving legitimacy to the privatization and unbundling of the NOC, separating and defining government’s commercial, policy and regulatory roles in petroleum operations as highlighted above. In an industry which adopts concessions and JV/JOAs, the ability of the NOC or government to fund its participation, operate independently, efficiently and transparently is very essential to the success and feasibility of gas utilization projects. Furthermore, in a PSC context, it is important to ensure that the practical implications of the negotiated terms and overarching legal framework are not self-defeating and counter-productive to the objectives of the parties. The provisions of the Upstream Contracts currently being used in Nigeria seem to have developed and more in line with current industry realities compared to the applicable laws and regulations. On the other hand, Mozambique seems to be able to review its model agreements and applicable regulatory framework in line with prevailing industry realities, even though the relevant institutions still lack considerable expertise and technical abilities. Although, as mentioned earlier the current Petroleum Law of Mozambique requires more detailed regulations and provisions 82

Oyewunmi (n5) at 546.

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regarding issues like domestic supply obligations, third party access, and acquired rights of existing concessionaires. The Model EPCC and contractual arrangements in Mozambique also requires among other things an update which reflects the new roles of the ENH regarding marketing and sales of produced gas, including domestic supply obligations. There is also a need to re-evaluate the financial and economic implications of ENH’s future role in exploration and production of the gas reserves. For example, as a result of the difficulties in funding capital requirements attached to its participation in concessions, the ENH may have to reduce its equity participation even though such a move may be politically and economically unpopular. 83Looking ahead, it is noteworthy that about 30% of global oil and gas discoveries made over the last 5 - 10 years have been in sub-Saharan Africa. Such developments seemingly reflect a relatively growing global appetite for African gas resources. Nigeria remains the biggest producer and consumer in the region, even though regulatory uncertainties and challenging business environment seems to limit its potentials.84 A critical challenge for Nigeria’s gas supply outlook is its ability to stimulate significant production of non-associated gas. Exploiting this resource requires inter alia; (i) a paradigm shift from an ‘oil-centered’ upstream petroleum industry to one which is both ‘oil’ and ’gas’ centered; (ii) establishment of the required framework to adequately incentivize the large-scale capital investment in gas development and utilisation; and (iii) de-politicizing and making decisionmaking processes more transparent and less arbitrary. Mozambique, on the other hand, appears to show that it intends to woo investors to exploit its resources, while also serving its domestic economic and industrial needs regardless of the enormous challenges its budding gas industry is facing. The monetization of the massive Rovuma-Basin gas reserves, for example, will necessitate developing new natural gas hubs and infrastructure in some of the most under-developed areas. These will also require institutional capacity and experience which may not be readily available locally. 4. Conclusion With the appropriate framework (legal, regulatory and contractual), prices and infrastructure in place, gas producing States can ensure they generate adequate revenue and sustainable economic growth. Consequently, private investors and partners can expect to have a fair return on investments, reasonable profits and certainty or transparency in the business environment. As the relevant legal and contractual frameworks in Nigeria and Mozambique develops and becomes more comprehensive or coherent, it is expected that these countries will be able to fully utilize the abundant gas resources and play a key role in the global gas demand and supply matrix in the decades ahead.

83

Frühauf (n61) at 27. International Energy Agency (IEA), 'African Energy Outlook: A focus on prospects in Sub-Saharan Africa' IEA Publications (Paris, France), pp. 1 – 242 at 10 – 15. 84

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