Taxpayers should expect tax authorities to intensify their efforts to re-examine and re-analyse all aspects of the tax laws. This means new issues may be raised on items that were previously ignored or have hitherto been accepted as industry practice.
The nature of the Oil business is such that net cash flow is negative until the commencement of the production and sales process. This is mainly because of the huge capital investment required to take the field to the commercial production stage. An Oil company must first recover its investment before enjoying positive net cash flow. The time lag between investment and profitability can be very significant. Under good pricing conditions, the more volume produced, the faster the rate of cost recovery and the sooner the company gets through the pay-back period. Hence, the promise land of profitability will be farther away under low pricing regime.
It is therefore critical in this period of depressed oil prices to ensure that there are no risk of additional tax costs that may erode net cash flow, due to disallowance of items claimed in tax returns; and risk of material restatement of tax provisions in financial statements.
Companies must begin to look in details at their tax assumptions and the tax positions taken during the period of high oil prices that may create uncertain tax position for them. These uncertain tax positions are often as a result of taking aggressive tax positions; adopting untested tax advice; reliance on the outcome of the tax audit of industry peers; reliance on previous tax agreement with the tax authority, grey areas in the law, and so on. Before now, the attendant tax risks were considered, at best of low-impact, as they were in most cases immaterial given the high level of revenue and profits. This is obviously no longer the case.
Also, owing to the pressure on government to increase non-Oil revenue, companies need to start preparing for more tax transparency and scrutiny. More so, the current global trend is that most tax authorities are gradually introducing new measures to incorporate the recommendations of the recent OECD action plans against tax avoidance, including the signing of information-sharing agreements. Thus, companies should always assume that dealings with the tax authority of one country will be shared with the tax authorities of others. There is also increasing focus on the basis for inter-company service charges, royalties, and inter-company finance costs. These underscores the importance of always taking a legally sustainable position and preparing adequate documentation to support the positions taken.
In addition, taxpayers should expect that tax authorities will intensify their efforts to re- examine and re-analyse all aspects of the tax laws. This means new issues may be raised on items that were previously ignored, been silent about, or have hitherto been accepted as industry practice.
Some of the potential risk areas for companies in the Oil and gas sector include:
1) Restriction of capital allowances
The tax law allows an accelerated capital allowance deduction, and where applicable, a reduced Petroleum Profit Tax (PPT) rate of 65.75% until the pre-production costs are fully amortised. However, the Petroleum Profit Tax Act (PPTA) applies a restriction to the amount of capital allowance (CA) that can be claimed in each year of assessment. The capital allowance deductible is restricted to the lower of actual amount computed and 85% of assessable profit less 170% of Petroleum Investment Allowance (PIA).
There are however odd occasions, where the PIA granted is so high, or the assessable profit is so low (especially as a result of low oil revenue), that the calculation of the applicable restriction results in a negative number. The industry practice has been that this computation is ignored and the restriction is limited to only 85% of assessable profit; which in effect means that a minimum tax will be payable on 15% of assessable profit. However the FIRS has recently been disputing this treatment in the audit of some companies, and instead posits that no capital allowance will be granted in such years, but carried forward to subsequent years. There is the need for companies to ensure appropriate legal basis before adopting any position while the FIRS should take an objective, rather than aggressive view where the law is unclear.
2) Intangible Drilling Costs (IDC) deduction
Companies need to pay careful attention to the detailed definition of what constitutes an IDC. It is sometimes possible that items are grouped under a tangible asset cost code by the accountants for ease of classification, even though a review of the substance might show a considerable amount of IDCs included. There may therefore be a significant level of uncertainty around the claiming of deduction for IDCs in the tax returns.
3) Claiming deduction for acquisition costs
The interpretation of the PPTA section that relates to claiming deduction on acquisition costs has posed a challenge to many new entrants, especially following the several divestments by the Oil majors. The FIRS on one hand has sought to restrict the deductibility of acquisition costs to the original costs incurred by the Seller, hence excluding any premium paid over those costs. On the other hand, the buyers have maintained that the full consideration paid are claimable.
4) Pioneer status granted to oil companies
Without any formal guidance from the tax authority, many pioneer oil companies are in a dilemma as to how to apply the provisions of IDITRA, which draws heavily from the provisions of CITA to petroleum operations that are extensively catered for under the PPTA. Questions are being asked as regarding the suitability and legitimacy of such incentive to the oil industry especially at the time of high Oil prices.
5) New entrant rate
It is not often clear as to when the so-called “new entrant rate” of 65.75% should apply. In principle, this lower rate is applicable until a company fully amortises its pre-production expenditures i.e. in effect, the first 5 accounting years. A common issue is whether the rate applies to new owners or new fields (i.e. undeveloped fields)? Is the rate applicable when a company starts producing, or when a field starts producing? What is the legislative intent?
6) Hybrid contracts
The mixing up of the feature of the main types of contract models (e.g. JV/concession system and Production Sharing Contract models) creates what is commonly known as a “hybrid contract”. The main driver is usually commercial but could also be political. However, interpretation of these contract types from a tax perspective often pose a challenge to companies. Typical issues include if block-filling is allowed, ownership of capital allowances, etc.
7) Other Potential risk areas include
- Qualification for the Gas incentives in the upstream and downstream sector
- Disputes on the applicable royalty system – tranche or flat rate?
- Taxation of hedging transactions
- Treatment of non-operating interest e.g. overriding royalties, net profit interest etc
- Cost allocation and time-writing issues
- Consideration structuring and balancing adjustments
- Treatment of abandonment costs
In conclusion, while Oil companies are intensifying efforts to adapt to the current low oil price conditions, they must also incorporate measures to prevent cash tax leakages. More importantly, the board and management of these companies need to be proactive and take a prudent decision to rethink and review their tax positions. Where necessary, steps should be taken to remediate to eliminate or reduce uncertainties especially where adequate provisions have not been made.