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Gas is a significant energy resource, viewed as a global transitional fuel primarily because of its low greenhouse gas emissions. Nigeria is endowed with high volumes of gas deposits or reserves. As of January 2025, the country’s total gas deposit was 210.54 trillion cubic feet (TCF) – an increase from 208.83 TCF in 2023. This comprised approximately 101.03 trillion cubic feet of associated gas (AG) and 109.51 trillion cubic feet of non-associated gas (NAG).

Despite these rich gas endowments, crude oil has enjoyed a historical preference to the detriment of gas. The current contractual, regulatory, and fiscal arrangements have favoured the development of crude oil projects. Gas monetisation and commercialisation have largely been left to play in the game of chance.  

In recognition of the foregoing, the President Bola Tinubu administration has shown a commitment to the gas agenda and full utilisation of gas deposits. Through its “Decade of Gas” initiative and renewed commitment to fiscal and regulatory reforms, the Federal Government (FG) aims to achieve full utilisation of the nation’s vast gas resources and position Nigeria as a gas-powered industrial economy. 

In furtherance of this initiative, the FG has set an ambitious target of producing 10 billion standard cubic feet (scf) of gas per day as part of its wider strategy of transforming Nigeria from just an oil-rich nation solely dependent on crude oil to a major gas-powered economy by 2030, leveraging its reserves to boost domestic power generation and industrialisation, increase exports, and reduce gas flaring. 

Buoyed by the recent policy direction, which is characterised by the introduction of specific fiscal incentives such as tax credits, the country has received Final Investment Decisions (FIDs) for three critical projects. Two of these are Shell’s $2 billion new gas project in the shallow offshore H1 Field in OML 144 – a joint venture with Sunlink Energies and Resources Limited, and Total’s $550 million NAG project located in OML 58. These projects represent a significant milestone in Nigeria’s journey to unlock its abundant gas resources for domestic utilisation and export. 

While these positive developments demonstrate the critical importance of legal, fiscal, and contractual frameworks for the commercialisation of gas projects, they also represent a restoration of the local and foreign investors’ confidence in gas development and a repositioning of Nigeria as a competitive investment destination.

The foregoing positive developments notwithstanding, gas development has received little or no attention owing to several factors.

Gas Ownership and Commercialisation

The ownership of oil and gas resources found in onshore, shallow water, and deep offshore locations within the territorial waters, continental shelf, and exclusive economic zone of Nigeria is vested in the FG. The government can maximise these resources by undertaking their appraisal, exploration, production, and development through NNPC Limited. Given the cost-intensive nature of oil and gas operations, the national oil company executes various contractual arrangements with international oil companies (IOCs) and indigenous oil companies to develop oil and gas fields. 

While noting the importance of these contractual arrangements to the oil and gas industry’s development, their terms are typically skewed in favour of crude oil production. The contractual structure allocates and completely vests all gas (either alone or in association with crude oil) produced from the fields in the FG, with limited direct commercial upside for the partners in most cases. 

These contractual arrangements typically range from production sharing contracts to joint ventures and sole risk contracts. The government, through NNPCL, would enter into one of these contracts with the IOCS and indigenous oil companies as partners, with these core features: Under the joint venture arrangements, the FG and partners jointly contribute the costs of exploration and production in proportion to their respective percentage holdings or participating interests in the relevant asset. In production sharing contracts, the contractor fully bears the costs of exploration and development and recovers allowable costs from production, after which profits are split between the parties, with the FG retaining legal title to the resources. In sole risk contracts, the company or partner assumes all the risks of exploration and production, retains all the oil produced for itself, and is only responsible for making statutory payments, including royalties and taxes to the government. 

The complete vesting of gas ownership on the FG in these contractual frameworks adversely impacts the economics and profitability of gas projects. This has not only encouraged gas flaring (in case of associated gas) but also limited investment in and/or financing for gas compression, separation, gathering, processing, and transportation infrastructures. Moreover, gas has not offered good incentives for development, as oil asset holders are primarily concerned with strong return on investment. Commercial lenders’ financing portfolios have also focused on crude oil projects. 

Despite these dynamics, there exists huge value in Nigeria’s undeveloped natural gas reserves. While there may be a need to restructure existing contractual treatment of gas, there is a pragmatic case for using an alternative financing structure, such as the Funding and Technical Services Agreement (FTSA), to unlock requisite capital and technical expertise for gas project development. 

Viable of FTSA  

Conceptually, the FTSA is a contractual arrangement which effectively blends financing with the delivery of specialised technical services for the development of a project. It is a blueprint that specifies the terms and conditions governing the partnership between an asset owner (the asset holder) and a Funding and Technical Service Provider (FTSP).

The primary purpose of the FTSA is the provision of funding and technical expertise or services by an FTSP for the exploration, development, production, and construction of designated oil and gas assets. In return, the FTSP is compensated through a share of the project's proceeds, which may be in the form of direct payments from revenue or an allocation of physical crude oil barrels or gas products (depending on the underlying reserves). 

In essence, the FTSA allows for significant capital injection and accelerated development by a third party with demonstrable financial capacity and technical expertise, without necessarily altering the ultimate ownership of the underlying petroleum assets, thus limiting the FTSP’s exposure to sovereign or counterparty risk.

An effective FTSA must clearly allocate risks and define mechanisms that align the parties' commercial objectives. The FTSA typically contains several clauses, the critical of which are discussed below:

Scope of Services: The FTSP provides all necessary funding for both capital expenditures (CAPEX) and operating expenditures (OPEX) for the defined project – the specific scope and details of which will be clearly spelt out in the FTSA. For gas projects, the FTSA will further specify the FTSP’s role as technical partner and define its responsibilities, which may be divided into technical and field services. The former entails services that may include the provision of strategic, business planning, administrative, and managerial oversight. The latter covers the full spectrum of on-the-ground operations, from procurement of relevant materials to seismic acquisition and drilling, facilities construction, and installation and production maintenance.

In gas project development, the FTSA designates the FTSP as the technical partner responsible for the overall technical, financial, and operational management of the project, including supervision of associated and non-associated gas infrastructure development.

Governance Structure: For management efficiency, FTSA also establishes governance structures to oversee the operations of the oil and gas asset. A Joint Project Management Team (JPMT) and a Field Management Committee (ManCom) may be set up to oversee operations, with each committee playing different roles. The JPMT may handle day-to-day technical and operational management, such as drafting annual work programmes and budgets, developing the field development plan, assessing production optimisation opportunities, planning and design, among other related functions. On the other hand, the ManCom provides overall strategic oversight and approves major financial and operational matters, including but not limited to value maximisation, field development, and production plans, amongst others.

Funding Mechanisms and Financial Provisions: Critical to the FTSA are its funding mechanisms and financial provisions. Given the model’s investment-driven nature, revenue recovery and profitability must be clearly defined at the outset. At the core of this model are the concepts of cost recovery and compensation.

Cost recovery entails the mechanism through which the FTSP recoups its entire investment. FTSAs employ one of two primary models, each with a distinct risk profile: (a) In-kind waterfall, in which case the FTSP is repaid through a direct allocation of physical barrels of crude oil. This model exposes the FTSP to commodity marketing, logistics, and price volatility risks. (b) In-cash waterfall would have all revenues from hydrocarbon sales paid into an escrow account. The FTSP is repaid in cash in accordance with a strict priority of payments. This model effectively insulates the FTSP from marketing risks but introduces counterparty and currency risks.

Compensation and internal rate of return (IRR) represent FTSP's profit. It is typically structured as a preferential share of the project's net proceeds (cash or barrels) until a pre-negotiated target IRR is achieved. The IRR serves as a proxy for the project's risk; higher-risk projects command a higher target IRR. The agreement term is often automatically extended until the targeted IRR is met, transforming it from a mere target into a contractually protected return that aligns risk with reward.

In addition to the foregoing, the FTSA will clearly define the term or duration of the agreement with the operator of an asset, their general joint and several obligations, the parties’ respective representations, and the warranties and termination events.

Commentary 

It is important to note that FTSAs are not new to the oil and gas industry. They have long served industry participants as the blueprint for an effective commercial framework between asset holders and third-party technical and financial partners. Given their structure, FTSAs provide an efficient vehicle for attracting capital from third-party investors or financiers to support gas development and commercialisation. 

As already noted, the model offers the third-party FTSP a viable path to participate in exploration and production without undergoing full licensing and regulatory process, while still retaining the opportunity to recover capital through an agreed revenue recovery mechanism. It offers a win-win situation for both the asset holders and the FTSP. 

Given the FG’s recent investment drive to fully monetise the country’s gas reserves, now is an opportune time to leverage the FTSA framework to unlock value. To the extent that the necessary legal, financial, and technical due diligence is competently done before the consummation of any FTSA arrangement, this model can offer private sector players or investors an opportunity to invest in the oil and gas industry while simultaneously contributing to accelerating Nigeria’s energy security, transition and socio-economic goals. 
 
Viyon Ojo is of the Legal and Compliance Department of Newcross Petroleum Limited.