A Critical Review of Upstream Provisions of the Federal Government (Part2)

1. Introduction

The first part of the article focused on institutional elements of the latest Nigerian Federal Government reform proposals. This part focuses on the operational aspects and reviews issues relating to licensing and environmental issues.

2. ACREAGE CONTROL & LICENSING

Like the Official Version of the Bill, Version IV vests all unallocated acreages in the Directorate on behalf of the Federal Government of Nigeria. It is suggested that a body saddled with the responsibility for detailed policy making should not hold acreage, which is an implementation issue. It would be more appropriate to vest acreage in the Inspectorate, which in its regulatory capacity is involved in acreage management.

A National Grid System is introduced to this version under section 270(1). The system would be used for the definition of license and lease areas, relinquishments etcetera. This is a welcome introduction and would serve to provide a uniform basis for acreage control and as such should be adopted by the legislature.

LICENSES AND LEASES

Version IV of the Bill provides for three upstream licenses; the petroleum exploration licence (“PEL”), the petroleum prospecting licence (“PPL”) and the petroleum mining lease (“PML”). Whilst the PPL & PML were provided for in the Official Version, the PEL is introduced in this version. The objective of its introduction may be to cater for exploration companies, which primarily explore for petroleum and sell data to those which seek to exploit it.

A major departure from the Official Version is the recognition that PPLs and PMLs may be in respect of crude oil and natural gas (Section 271(4) of Version IV). Section 257(1) of the Official Version states that: “Every petroleum prospecting license or petroleum mining lease shall clearly state that it shall be in respect of crude oil or natural gas but not of both crude oil and natural gas.” The proposed amendment is commendable as it was never clear why the government proposed a dichotomy between products which usually can be found together.

The introduction of a differentiation between the qualifications required by an operator and a non-operator for the purpose of licensing is also noted and commended (Section 271(6)(a) & (b) of Version IV ). The only qualification necessary with regard to non-operators is the means to finance its obligations under any license. This appears to be appreciated in the Inter Agency Memorandum.

It should also be noted that Version IV has changed the character of potential licensees. Under the Official Version, licences or leases may be granted to two categories of companies- the National Oil Company and indigenous oil companies.Version IV provides for licenses and leases to be granted to the National Oil Company and to a winning bidder of an acreage bid round.[3] The choice not to limit licenses and lessees essentially to local companies would encourage a wider pool of bidders. It may however be regarded as discouraging the efforts to build strong local players in the Nigerian oil and gas industry.

PEL

The PEL essentially replaces the oil exploration license (“OEL”) under the Petroleum Act 1969. It proposes to grant a non-exclusive right to carry out geological, geophysical and geochemical exploration of petroleum.[4] It also allows for a PEL to cover an area that includes PPLs and PMLs.[5] This would appear to interfere with the exclusive rights granted to the holder of a PPL under section 275(a) and the holder of a PML under section 281(1). It is suggested that this ambiguity needs to be resolved. It is suggested that a PEL should not be allowed to cover existing PPL or PML areas.

PPL

The holder of a PPL is granted an exclusive right to carry out petroleum exploration operations and has the right to carry away and dispose of crude oil or natural gas won during prospecting operations (Section 275 of Version IV). In terms of duration, the distinction between PPLs granted over land & shallow waters and deep water areas & inland basins is maintained. However the duration with respect to land and shallow waters is increased to seven years under Version IV (Section 276(a) of Version IV) as opposed to five years under the Official Version (Section 261(a) of the Official Version). The period of 10 years for deep water areas and inland basins is maintained. In both areas however, Version IV breaks down the term of the PPLs. The table below graphically illustrates this.

PPL Duration under the Official Version & Version IV

Area Official Version Version IV
Land & Shallow Waters Not more than 5 years Not more than 7 years consisting of:

 

  1. Initial period of 3 years
  2. Renewal period of 2 years
  3. Appraisal period of 2 years
Deep Water Areas & Inland Basin Not more than 10 years Not more than 10 years consisting of:

 

  1. An initial period of 5 years
  2. Renewal period of 3 years
  3. Appraisal of 2 years

MINIMUM WORK COMMITMENTS

Version IV also introduces provisions in relation to minimum work commitments. The main purpose of minimum work obligations is to maximise exploratory activity in the licensed area in a timely manner.[6] This is done by imposing terms on the licensee to carry out specific work in a specified period.[7] Section 277(2) imposes an obligation on the licensee to commit to drilling of at least one exploration well to a specified minimum depth. Such a commitment must be supported by a bank guarantee or performance bond from a reputable international bank[8]. The work commitment may also be used as a single bid parameter or as part of the bid parameters in the award of a PPL. The introduction of a framework for the work commitment process is laudable, it is suggested however that some of these provisions would need to be revised to maximize the benefits of the process.

Firstly, by specifying the minimum drilling requirements in legislation, it ties the hands of the regulators and does not provide for flexibility in accordance with field specifications. Further, the provisions do not explicitly tie the completion of the work commitment in the initial period to the renewal process; such an explicit tie would be useful to provide a clear basis for license renewals. Additionally, whilst there is a provision for a bank guarantee or a performance bond for the full amount of the committed work, there are no provisions for a reduction in the value of the guarantee or bond based on the value of money spent in carrying out the work commitment. It should also be noted that contrary to the spirit of local/Nigerian content, the performance bonds or bank guarantees must be provided by an international bank as opposed to a Nigerian bank.

COMMERCIAL DISCOVERY

Version IV also makes more detailed provisions with respect to commercial discoveries and field development plans. A commercial discovery is defined as “…a discovery of crude oil, tar sands, bitumen, heavy oils, extra heavy oils, natural gas or condensates within a petroleum prospecting licence which can be economically developed in the opinion of the licensee, after consideration of all relevant economic factors normally applied for the evaluation of crude oil, natural gas or condensate evaluation or development”.[9] Unlike under the existing Petroleum Act, this definition does not peg commerciality to a certain number of barrels per day but makes it subjective based on the licensee’s circumstances. This recognises the fact that the commerciality of a discovery is significantly dependent on the economic condition of the holder of the licence.

Upon the declaration of a commercial discovery, the licensee must submit a field development plan to the Inspectorate within 120 days (Section 278(1) of Version IV). The development plan must be approved by the Inspectorate within 90 days, if it meets certain criteria.[10]

RELINQUISHMENT

Relinquishment Provisions under Version IV

Relinquishment Period Version IV
Upon expiry of initial exploration period 50% of original license area
Upon the expiry of the renewal period All parcels that are not part of PMLs, appraisal areas or significant gas discovery retention areas
Upon expiration of the PPL All acreage that is not included in PMLs, appraisal areas or significant gas discovery retention areas

PETROLEUM MINING LEASE

A PML may be granted to a holder of a PPL who has satisfied the conditions under the PPL, has made a commercial discovery, and has received approval for the related development plan from the Inspectorate.[11] The holder of a PML shall have the exclusive right to carry out upstream petroleum operations in the lease area.[12] The grant of a PML shall be on the basis of a firm commitment to develop and produce the commercial discovery made in the lease area or to restart or continue petroleum production.[13]

Version IV also introduces the Domestic Gas Supply Obligation (“DGSO”) and requires all existing and future petroleum mining lessees[14] to comply with their obligations as prescribed by the Midstream Agency. Any licensee that does not comply with the DGSO would be prohibited supplying gas export operations.[15]

Under section 283(1), a PML may be granted for not more than twenty years, but may be renewed for a further period of 10 years, after which the lease area must be relinquished to the Directorate.[16] A PML which is not in commercial production within five years may be revoked.[17] A lease that has been in commercial production which has terminated for a period of one hundred and eighty days other than reason of force majeure may also be revoked.[18] The lessee is also required to relinquish all parcels that are not in commercial production after ten years of granting the lease.

PPL & PML AWARD PROCESS

The grant of a PPL or PML must be by a bidding process conducted by the Directorate or by the National Oil Company.[19] Under both versions, such a bidding process must be conducted in consultation with the Inspectorate. Version IV includes an improvement to the Official Version by requiring that the Minister may only award licences to winning bidder pursuant to the bid process.[20] It only introduces the criteria for determining a winning bid, which may be one or a combination of the following:

  1. Signature bonus;
  2. Royalty percentage;
  3. Work commitment in terms number of wells to a specified minimum depth;
  4. Work units.[21]

The introduction of these parameters would strengthen the provisions of the final Petroleum Industry Bill if included.

ASSIGNMENTS, MERGERS & ACQUISITIONS

The provisions of Version IV in relation to the assignment of licences/leases basically mirror those of the Official Version, save for the inclusion of a provision that any assignment, merger or acquisition would be “…subject to a fee equal to 2% of the fair market value of the transaction…”.[22] This introduction would negatively influence the cost of doing business in Nigeria and would impact on the ability of license holders to freely trade their rights. It is not clear how “fair market value” would be determined. The silence on this matter suggests that this would be based on the discretion of the Inspectorate. The draft does not propose a mechanism by which the judgment of the Inspectorate may be challenged in this regard. Finally the provisions do not take into consideration assignments, mergers and acquisitions between related parties, which may not necessarily be towards direct financial gain. It is therefore suggested that these issues be taken into consideration by the National Assembly in considering this draft provision.

PRODUCTION SHARING CONTRACTS & OTHER UPSTREAM DEVELOPMENT CONTRACTS

Under section 272(1) of Version IV, where a Minister grants a licence or lease to the winning bidder of an acreage bid process, such a winner, whether NNPC Ltd. or any other company, may enter into any contract for exploration, prospecting, production and development of oil or gas as the case may be.[23]

Version IV also creates another set of upstream development contracts by virtue of the provisions of sections 271(2) (b) and 272(2) (b). Under 271(2)(b), the Minister may, with the approval of the Directorate, grant NNPC Ltd. a license or lease after an open and transparent bid process for potential contractors has been conducted on the basis of a model contract approved by the Directorate. Section 272(2) (b) describes those model contracts as production sharing contracts, risk service contracts, and any other similar contract. Part VIII of Version IV goes on to provide for the fiscal content of the contracts entered into by NNPC Ltd.[24]

The effect of this two tier structure is that the National Oil Company is not required to always compete for acreage awarded to it. This provides it with a significant advantage over other companies and would ultimately hinder the ability of the NOC to compete. Additionally in the position where some of the shares of the entity has been divested as envisaged by the draft provisions, this considerable incentive would be in the hands of just a few and not the national treasury.

TREATMENT OF SUBSISTING PRODUCTION SHARING CONTRACTS & RISK SERVICE CONTRACTS

Version IV does not appear to specifically address how subsisting PSCs and RSCs would be treated under this arrangement. These were addressed in the Official Version.[25] It is necessary to address this issue as a number of provisions of subsisting PSCs have a regulatory flavour, which would be unsuitable to retain where the holder of the license is now a private company. These comments also apply with respect to any upstream development contracts that may be signed in the future, it is necessary to ensure that matters which are strictly regulatory are not included in such a contract so as not to arrogate excessive power to the National Oil Company.

ENVIRONMENTAL PROVISIONS

The Version IV draft improves on the environmental issues related provisions in the Bill. Instead of the requirement for the licensee/lessee to submit an environmental programme (“EP”) or an environmental quality management programme (“EQMP”) as required under section 283(1) of the Official Version[26] it now only requires the submission of only an “environmental management plan”.[27] By focussing on one type of programme or plan as opposed to two which were indistinguishable, this proposal is preferable to the original version. However, the contents of the environmental management plan remain the same, which therefore raises the point as to its similarity with the provisions requiring an environmental impact assessment (“EIA”) under the Environmental Impact Assessment Act. Under these provisions EIAs would be required with respect to most oil and gas operations. The provisions of Version IV do not seek to repeal the Environmental Impact Assessment Act, nor do they seek to void its applicability to oil and gas operations. The effect therefore if these provisions are adopted is that there would be a duplication of efforts by oil and gas operators. We therefore suggest that these issues be taken into account.

We note the deletion of provisions relating to the States and Local Governments being financially responsible for environmental damage caused by sabotage (Section 261 of the Official Version).These provisions may indeed be unconstitutional.

Version IV also provides for financial provisions/contributions to be made by a licensee or lessee to a remediation fund. This version makes this fund subject to audit by the “lessee”[28]. It maintains the requirement for a licensee or lessee to “annually assess its environmental liability and increase its financial contribution to the satisfaction of the Inspectorate”.[29] This requirement to annually increase a licensee/lessee’s contribution does not reflect realities as the assessment of the environmental effects of a company’s operations, could very well show a decrease in the potential environmental liability. It may also have the effect of stifling innovation as there is no incentive to develop better processes or use more environmentally-efficient equipment in operations. Additionally, the provisions remain silent on the mechanism for reimbursement of the money paid into the fund when upstream operations end. Finally, it may be suggested that if it is desirable to retain such an option, it may be useful to adopt the model utilised in relation to work commitments and field development programmes, which is to provide a bank guarantee/performance bond. This way, cash would not be tied down for a significant amount of time, whilst still ensuring that there is a way to fund the remediation of the environment due to damage caused by the operations of a licensee/lessee. Version IV also includes provisions for the payment of gas flaring penalties.[30]

RELINQUISHMENT OF EXISTING LICENSES/LEASES

Arguably the most contentious aspects of the provisions of Version IV in the upstream sector are in relation to mandatory relinquishment of license areas. Under Section 291, existing licensees & lessees are required to select areas for which the licensee or lessee is prepared to make a declaration of commercial discovery, for which development is underway, in which regular commercial production is occurring or for which the licensee or lessee is prepared to make a declaration of significant gas discovery. All such areas would be converted into PMLs, and any area not so selected must be relinquished. These provisions raise questions as to whether it amounts to compensable expropriation. Due to volume constraints, the examination of this issue is beyond the scope of this article and would be subject to a more detailed review in a subsequent article.

3. GENERAL COMMENTS

Although there is still room for improvement, the upstream provisions in Version IV are a significant improvement on the Official Version. They appear to reflect a more considered approach to upstream petroleum issues. The existence of two government sponsored versions of the same Bill however creates a number of challenges for the National Assembly in organising and selecting the appropriate provisions for inclusion in the final legislation. It also provides a challenge for stakeholders in the review of the proposed legislation. It is suggested that for a streamlined and efficient process, it may be better for the Government to withdraw the Official Version and to submit Version IV or a variation of it. There are of course genuine concerns as to the time it would take to pass the Bill if this course is taken, particularly in view of the potential abridged legislative timetable due to the upcoming elections. It is however suggested that such a process would provide better quality legislation. In view of the fact that the current legislation has been in place for over forty years, the quality of the process and its product should be of paramount consideration.

[1] Section 269(1) of Version IV

[2] Section 257(1) of the Official Version. The Official Version defines an indigenous oil company as a company:

  1. Engaged in the exploration for and production of crude oil and natural gas of which sixty per cent or more of its shares are beneficially owned directly or indirectly by Nigerian citizens or associations of Nigerian citizens;
  2. Which meets the requirements of any guidelines or regulations that may be issued by the Directorate or Inspectorate; and
  3. Which is accredited as an indigenous oil company by the Directorate or Inspectorate… Section 467 of the Official Version.

[3] Section 271(2)(a) & (b) of Version IV

[4] Section 274(1) of Version IV

[5] Sections 271(3) & 274(3) of Version IV. It should be noted that section 274(3) refers to “petroleum mining licences” as opposed to “petroleum mining leases”.

[6] Geoff Hewitt and Adrian Hill, “Offshore Licence Operations: The Exploration Phase”, in Terence Daintith et al, United Kingdom Oil and Gas Law (London: Sweet & Maxwell, 2005).

[7] William Onorato & J. Jay Park, “World Petroleum Legislation: Frameworks that Foster Oil and Gas Development”, 39 Alberta L. Rev. pp. 70 -126.

[8] Section 277(15) of Version IV

[9] Section 526 of Version IV. It seems unusual to include tar sands and bitumen in this definition as they have been traditionally treated under the solid minerals regime in Nigeria.

[10] The criteria include- an approved National Content Plan, an approved environmental management plan, provision for routine gas flaring etcetera. It is not clear if the 120 days within which to submit a development plan under section 278(1) would allow a licensee to meet all these obligations. Before the provisions are adopted by the legislature, it would be necessary to map the time it would take to get those approvals.

[11] Section 280(1) of Version IV

[12] Section 281(1) of Version IV

[13] Section 281(3) of Version IV

[14] This is incorrect from a technical perspective as there are no “existing petroleum licensees”. It is suggested that it be amended to include current holders of oil mining leases.

[15] Section 282(4) of Version IV

[16] Section 283(3) of Version IV. This is in contrast to the provisions of the Official Version which provides for the duration of twenty years renewable for 20 years at each renewal period. Section 239 of the Official Version.

[17] Section 283(2) of Version IV. It is not clear who the right to revoke rests with. Additionally, the right is discretionary, and there is no requirement to take into cognisance issues such as force majeure or any special circumstance, which may affect the ability to achieve commercial production. It is therefore strongly recommended for these issues to be taken into consideration by the National Assembly.

[18] Section 283(4) of Version IV

[19] Section 289(1) of Version IV

[20] Section 271(2) of Version IV. Under the Official Version, this was not quite clear.

[21] Section 289(2) (a) & (b) of Version IV. It should be noted that there is no definition or description of what constitutes “work units”.

[22] Section 292(5) of Version IV

[23] It is suggested that these provisions would entitle bid winners to enter into production sharing contracts, risk service contracts and the like without a requirement to obtain permission from the Directorate or the Inspectorate.

[24] Sections 494-506 of Version IV

[25] Section 230(2) of the Official Version

[26] One of the major criticisms of the structure under the Official Version was the fact that the EP & EQMP were not distinguishable and it was not clear under what circumstances one would be required over the other.

[27] Section 299(1) of Version IV

[28] Section 302(1) of Version IV. It should be noted that this provision only subjects the fund to audit by the lessee and does not include the licensee. We suggest that this be amended if the provisions are to be adopted.

[29] Section 302(3) of Version IV

[30] Section 300 of Version IV

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