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How marginal field bidders should structure deals and deploy capital to succeed – Mama

Many of the fields on offer in the ongoing marginal field bid rounds includes those unable to be developed many years ago. Some are still lying fallow after successful bids largely due to the inability of operators arrange suitable deals to develop them. Chijioke Mama, an energy transaction advisor and Doctoral Researcher in Business Management, tells BusinessDay’s ISAAC ANYAOGU the strategies prospective marginal field bidders can adopt to structure deals and deploy capital to bring their fields to development.

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What is the ambience in the petroleum sector regarding the 2020 Nigeria marginal field bid round?

Having waited for almost 20 years; the reported rush for these assets is not surprising. But available data show that acquiring an asset is cosmetic; the real hurdle lies in profitably developing the asset, which has proven to be an arduous, often underestimated task. The outlook is made worst by the current commercial clime for oil in the global market, as well as, some failed efforts in the 2003 licensing round.

Given that the Niger Delta is a mature basin, I have empirical evidence from a 7 year critical study and analysis to support the postulation that the successful operation of a marginal field has less to do with the asset and more to do with the promoting structure and capital deployment strategies. The general understanding, however, is the reverse.

If it’s less about the asset what collaboration and capital deployment strategies are then required?

Collaboration strategies for marginal field development vary widely; whether they are for capital deployment or technical service provision. By collaboration, I am referring to the sometimes precarious Joint Ventures and partnerships commonly used by E & P companies.
These Deal structures – being more sensitive factors than technical skills or asset quality – must be diligently approached. On the one hand there is the need to optimize the participating structure, where there are several E&P companies working as a consortium. On the other hand you have an equally sensitive Farmor-Farmee relationship that requires proper structuring and management.

In all cases, the necessity for a carefully and diligently negotiated structure is evident. While there is a long list of common and legitimate considerations, some are indisputably more sensitive. Yet it’s common to see, negotiators, drafters and deal parties using a common approach or template to transact. Loosely & hastily structured Joint ventures or partnership for upstream capital deployment is one of the most underlying causes of crises or poor performance in marginal field development. Therefore it becomes very imperative that parties collaborating or intending to collaborate under the various permissible deal structures in a JV, should stress-test the vehicle early enough.

How then should capital deployment in marginal fields be optimized?

Unarguably, these are tough times in the global petroleum industry and that might cause funding apathy for Nigerian marginal fields. However, legacy financiers may rely on the historical, commodity price boom-bust cycle to appraise opportunities.

Thus, field development capital can be deployed using a variety of deal structures and strategies. Some common practices include Financial and Technical Service Agreements (FTSA), Equity Joint Ventures, Reserves-based lending and Risk Service Contracts.

The Suitability of any of these or other models will depend on the strength and primary motive of the collaborating parties. Each deal structure has its own risk profile and benefits but most will involve the assignment of some working interest or economic interest to the capital provider, recoverable as a percentage of distributable proceeds.

Some of these strategies involve providing capital to develop an asset on nonrecourse terms and without any collateral except petroleum production, which precipitates a unique transaction risk profile for the investor – in this case an appropriately structured collaboration will be the first mitigation mechanism.

Furthermore, recent advances in geophysical technology means capital providers now have means to pursue more reliable estimates of the resources in place by implementing additional scrutiny. Thus in addition to optimizing deal structure, financing decisions should be made on geophysical data that are complete, rational, consistent and reasonable as attested to, by a third party or unbiased entity.

What are the common pitfalls in marginal field deal structuring?

That will depend on the dealing parties and the kind of interest they have. Capital providers in particular must avoid yielding to a tunnel vision of the transaction. For instance, an entity providing finance and technical service in exchange for working or economic interest; will pay keen attention to the agreed payout formula, which can add greater risks to the recovery of invested funds.

Simply put, the mechanism and timeline for triggering reversionary interest and the scale of the premium to be received on their investment have to be objectively and carefully determined.

Given the uncertainties around field development work programs and unanticipated delays in receiving statutory consents and approvals, four years can easily become eight years, which can erode the financier’s profit.

For the asset-owning E&P Company or consortium, carefully managing the scope of farmor’s rights and influence in some issues is imperative along with optimizing the nature of any agreed obligation/duty to the farmor.

For instance, Farmor will usually ask that operator’s assignment of further interest in a field should not be made without their consent, which is the right to determine if any potential assignee is sufficiently qualified to participate in the asset.

Sometimes there are stringent restrictions regarding the assignment of lien to the farm out area, which may partially or fully limit access to innovative financing mechanisms such as reserves-based lending or revenue based finance. Through ignorance or negligence, the farmee may fail to negotiate for conditions that provide easy channels for third party participation in developing the field.

Seemingly harmless requirements such as farmor’s consent for all press releases regarding the field could pose subtle limitations. In one case, a marginal field operator reported difficulty in arranging a meeting with an IOC for over 6 months on a matter which was very exigent.

Other matters to be carefully negotiated include, default mechanism [for consortiums] whether it is “carry”, proportionate forfeiture of equity or total buy-out; Field Abandonment Security and the nature and extent of farmor’s required approval for annual work programs.
In an era of heightened environmental awareness in the Niger Delta and given that farmor will normally provide the asset on “as is where is” basis; the need for conducting a baseline environmental study on the farmout area, prior to entry is very critical.

In addition, since there is no uniform approach to the operational, legal and administrative design of any given collaboration, it cannot be overemphasis that the most sensitive issues must be cautiously approached and negotiated at the earliest possible instance. The need to have a rounded perspective on the commercial and operational aspects of any agreement cannot be overemphasized as well.

Can you compare the viability of the marginal field investment opportunity in 2020 with 2003?

I consider Nigerian marginal fields to be more attractive in this era than 2003. Some of the conditions that contributed to the marginal status of these assets have positively evolved in most cases.

For instance, previously stranded natural gas resources, in the Western Niger Delta region that was marginal due to the lack of export infrastructure or processing facility now has several alternatives within actual and planned natural gas pipeline infrastructure in the region, including ELPS 2, OB3 Pipeline and AKK.

This is further enhanced by the launching of the Nigerian Gas Transportation Network Code [NGTNC] which provides third party access to certain gas transmission and distribution infrastructure under streamlined operational & fiscal regimes.

Furthermore, if you consider that there are about three modular refineries nearing completion onshore Nigeria, then you see that onshore productions could have a faster and cheaper route to market.

The last 20 years have also provided opportunities to acquire and perfect [in country] several innovative capital deployments solution such as reserves-based lending and other variants of financial and technical services partnerships. For promoters who will operate with the right setting and surmount the external industry-wide challenges, the outlook definitely looks better now than in 2003.

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