Nigeria: Highlights Of Nigeria Hydrocarbon Tax And Allowances Under The Petroleum Industry Bill

Last Updated: 21 February 2014
Article by Ose Okpeku

The Petroleum Industry Bill PIB is the culmination of nearly eight years of work as the initiative of the BPE to steer the reforms of the Oil and Gas sector . The Oil and Gas Reform Implementation Committee was established in 2000, chaired by Dr. Rilwanu Lukman as Presidential Adviser on Energy. The resulting broad consultative process led to drafting of the Bill in 2008. It was submitted to the National Assembly (NASS) since early 2009 for enactment into law, to sanitise, and reduce the opacity in the petroleum industry1.

Despite several assurances especially by the Minister of Petroleum Resources from mid-2010, the National Assembly Class of 2011 was unable to deliver on enactment of the PIB. The process had stalled largely because of various 'versions' of the PIB in circulation, and diminished attention from 'the project' as a result of preparation for the April 2011 national elections.

On 18 July 2012, the Presidency forwarded the 223 page Petroleum Industry Bill (PIB) 2012 to the National Assembly, as an Executive Bill.

The PIB intends to repeal the provisions of the petroleum Profits Tax Act, (PPTA) Petroleum Act and some sections of the Companies Income Tax Act (CITA). It also introduces a new tax, called the Nigerian Hydrocarbon Tax.

This essay intends to highlight the introduction of Nigerian Hydrocarbon Tax and the various allowances available under the new Petroleum Industry Bill 2012.

A. Nigerian Hydrocarbon Tax (NHT)

Taxation of the oil and gas sector is regulated by the Petroleum Profits Tax Act Cap P13 LFN 2004 and this is charged at the rate of 85% of profit oil and 65.75& for companies yet to recoup their cost while under the Deep offshore production Sharing Contract Act, it is at a flat rate of 50% for the duration of the Production Sharing Contract. This is usually for a minimum of five and an aggregate of ten years.

Section 299 of the PIB provides for the introduction of the Nigeria Hydrocarbon Tax, while Section 313 states that companies in the upstream operation shall pay 50% NHT for onshore and shallow waters and 25% for bitumen, frontier acreages and deepwaters of their chargeable profits.

Section 313 (2) of the PIB provides that where a company carries on upstream operations in areas that are subject to more than one tax rate, the appropriate tax rates shall be levied on the proportionate parts of the chargeable profits arising from those operations, i.e. where a company's operation includes onshore and shallow waters and its operation also extends to bitumen or frontier acreages the tax rate applicable shall be measured to the extent of the operation carried out on that field.

B. Allowances

i. Deductions Allowed

Section 305 of the bill provides that within the context of the NHT in computing the allowable deductions shall exclusively qualify as such if the expenses were WENR incurred by the company in the course of its operation, all expenses shall be wholly, exclusively, necessarily and reasonably (WENR) incurred by the company. The allowable deductions are similar to the provisions of Section 10 of the PPTA, in this instance the word "reasonably" is included, but the bill did not provide a reasonability test thereby leaving it at the whims of the Federal Inland Revenue Service.

Section 305 (1) provides for where deductions are allowed; some of those instances are as follows:

a. Sums incurred by way of interest upon any money borrowed by such company, where service (FIRS) is satisfied that the interest was payable on the capital employed in carrying on its upstream petroleum operations except interest incurred under a Production Sharing Contract. It is unclear why PSCs are given such treatment, noting the huge capital outlay for exploration in deep offshore wells.

b. All sums set aside, in a fund by the company as decommissioning and abandonment expenditure is now tax deductible provided the funds are set aside.

c. Contributions to pension and other similar schemes/funds are tax deductible. The need to obtain approval for these contributions has been removed, as long as the scheme/fund is in line with the Pension Reform Act.

ii. Non-Allowable Deductions

a. Expenditure for the purpose of paying a penalty or fee relating to:

i. gas flaring; and

ii. domestic gas supply obligations.

b. Signature bonuses, production bonuses or other bonuses due on a lease or on renewal of a lease.

c. All general, administrative and overhead expenses incurred outside Nigeria in excess of 1% of the total annual capital expenditure.

d. 20% of any expense incurred outside Nigeria, except where such expenditure relates to the procurement of goods and services which are not available in domestically in the required quantity and quality and subject to the approval of the Nigerian Content Development and Monitoring Board.

e. Any legal and arbitration cost relating to cases against the FIRS or the Government, unless specifically awarded to the company during the legal or arbitration process.

f. Pre-incorporation cost.

g. Any cost arising from fraud, willful misconduct or negligence on the part of the company.

h. Insurance cost where such cost is earned by the company or an affiliate of the company.

i. Costs or fees incurred in obtaining and maintenance of a performance bond under a production sharing contract.

iii. Capital and Production Allowances

Under the PPTA, the total Capital Allowance (CA) that a company can claim in an accounting period is restricted to 85% of its assessable profits less 170% of its petroleum investment allowance (PIA). This restriction has been removed in the PIB. The removal of the restriction should encourage investment in the oil and gas sector and allow companies to recoup their capital investments within a shorter period of time.2.

The Fourth Schedule of the PIB provides that Qualifying Expenditure shall include expenditures incurred on plants, fixtures, machineries, storage tanks, pipelines construction of buildings, structures or works of permanent nature, drilling expenditure and acquisition of or rights over petroleum deposits. Para 2(3), excludes subsequent acquisition costs of rights to petroleum deposits/purchase of information on the existence or extent of such deposits therefore it shall be disregarded for purposes of qualifying petroleum expenditure (QPE) by the subsequent acquirer company. This will put to rest arguments that signature bonuses cannot be regarded as qualifying drilling expenditure pursuant to Para 1, 2nd Schedule PPTA.

Para 5, 5th Schedule PIBclarifies that Contractors financing the cost of equipment will be deemed to be the owner of QPE thereon for capital allowance purposes – unlike currently where the capital allowance is shared by PSC parties because chargeable tax is allocated between them in the proportion of their profit oil split.

Para (13) also inserts a new Para 7(3) to 2nd Schedule CITA asfollows: "where a licensee or lessee hasentered into a contract...and suchcontract for the transfer of assets to such licensee or lessee by the contractor, such transfer shall be valued as equal to the value of cost oil, cost gas or cost condensates paid for such assets ('the deemed income') and capital cost allowances shall be claimed against such deemed income in the hands of the licensee or lessee.

The contracting parties shall be entitled to deduct the expenditures for the creation of assets to be owned by a licensee of petroleum prospecting license or lessee of a petroleum mining lease."

The provision of Para 6(3), 5th Schedulethat any asset of which capitalallowances has been granted may onlybe disposed of on the authority of aCertificate of Disposal issued by the Minister of Finance or any person authorized by him, introduces bureaucracy that is reminiscent of the hugely unpopular requirement of obtaining Certificate of Acceptance on Fixed Assets (CAFA) by the Industrial Inspectorate Department of the Ministry of Industries for assets exceeding N500,000 in value in order to claim capital allowances thereon under CITA.

Para (11)amends CITA's 2nd Scheduleby adding the definition of qualifyingupstream petroleum expenditure andsetting out initial and annualallowances in respect thereof.

Section 314of the PIB provides for General Production Allowance (GPA) pursuant to 5th Schedulewhich replaces investment taxcredit/allowance (ITC/ITA) for Contractorsunder current PSCs. Unlike ITC/ITA which is a function (50%)of asset cost and applicable only in theyear of acquisition, the GPA for PSCs is"$5 per barrel or 10% of the officialselling price, for all production volumes." However, at firstglance – since ITC is a more beneficialincentive than ITA, pre-1998 PSCssubject to ITC may be more adverselyimpacted than post 1998 PSCs that aresubject to ITAs.Furthermore, the GPA does not apply tocompanies in joint venture operationswith NNPC (notwithstanding that they are currently entitled to Petroleum Investment Allowance (PIA) underPPTA).

Other GPA prescriptions are as follows:

a. for onshore– the lower of $30 per barrel or 30% of the Official Selling Price (OSP) up to cumulative maximum of 10 million barrels, and thereafter the lower of $10 per barrel or 30% of the OSP up to cumulative maximum of 75 million barrels;

b. for shallow water areas- the lower of $30 per barrel or 30% of the OSP up to cumulative maximum of 20 million barrels, and thereafter the lower of $10 per barrel or 30% of the OSP up to cumulative maximum of 150 million barrels; and

c. for bitumen deposits, frontier acreage and deep water areas-the lower of $15 per barrel or 30% ofthe OSP up to cumulative maximumof 250 million barrels per PML, andthereafter the lower of $5 per barrelor 10% of the OSP.

With the exception of (c), i.e. bitumen, frontier acreage and deep water, once the latter cumulative maximum thresholdhas been reached, the GPA will lapse;whereas currently, PIA (for JVs) or ITC/ITA(for PSCs) applies during the producing lifeof the asset.

The question may arise whether cumulating for the relevant threshold starts counting from the time the PIB is enacted or from historic production? For reasons of equity and fairness, the former would be the preferable approach.

With regard to gas production, where (potentially more favourable) incentives for utilisation of associated and non-associated gas currently apply, the PIB's

GPA make detailed respective prescriptions for onshore, shallow offshore and bitumen/frontier acreage and deepwater respectively.

Generally, where allowances cannot be fully deducted due to nil or insufficient assessable profits in an accounting period, these may be carried forward to subsequent accounting period. Also, where a field development produces a combination of crude oil, condensate and natural gas, the related GPA shall be taken separately. Where a field is covered by two or more Petroleum Mining Leases, the allowances for each PML shall be determined based on the total unitized production.

Where a lessee is producing crude oil with associated gas at the Effective Date and is flaring substantial volumes of gas, it could propose a development plan to significantly eliminate routine flaring. If same is approved by the National

Petroleum Inspectorate, the lessee shall be entitled to claim applicable GPA in the above table (herein) regarding natural gas and condensate attributable to such development plan.

Furthermore, all GPA thresholds are to be fixed on the total production per PML aggregated at company level subject to the following exceptions:

a. claims by Contractors in deepwater PSCs shall be ring-fenced per PML;

b. supplier of gas destined solely for the domestic market shall be entitled to claim production allowance per PML; and

c. where a shareholder holds 10% stake (directly or indirectly) in several companies, the companies shall be treated as one for the purposes of computing the GPA.

It is expected that when or if this bill before the National Assembly is passed and signed into to law by the President it will provide some clarity in the taxation of companies in the oil and gas sector of the Nigerian Economy, thereby deepening the opportunities that will be available for investors and stakeholders alike. However it must be noted that the PIB still retained the secrecy portion (Section 5) of the Petroleum Profits Tax Act which also precludes the court from having access to documents as it relates assessments, petroleum operations e.t.c. this as it stands contravenes the provisions of the Freedom of Information Act, which raises a poser whether what the government earns from the commonwealth of nation does not fall within the purview of a public information.

Footnotes

1. (El-Rufai: The Journey of the PIB)

2. (PIB Neswletter: Tax and Fiscal Highlights by Templars

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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