Long before the turn of the new millennium, Nigeria’s aspirations for the oil and gas industry were to:
- grow the daily crude oil production capacity from 2.3million barrels to at least 3 million barrels to enhance oil exports capacity;
- build between 3 and 4billion barrels of strategic national oil reserve;
- increase the quantum of Nigerian participation in the operation of the industry through a Nigerian content development policy, and
- boost the local refining of petroleum products to curb imports.
As a country reputed to be a natural gas province producing oil, the country’s other strategic aspiration was to harness the huge natural gas resource endowment into veritable sources for energy supply for domestic and industrial users as well as for exports.
Nigeria’s endowment in natural gas contingent (discovered) reserve is estimated at over 600 trillion standard cubic feet, which is at least ten times the volume of producible crude oil reserves.
This outside additional 209 trillion cubic feet of the commodity considered prospective (not discovered), with over 90% chance of producibility.
So far, there has not been any deliberate policy by the government to search for and develop the country’s natural gas potentials.
The reserves so far discovered were accidental, primarily in the course of exploration for crude oil (associated gas).
Even the associated gas reserves that have been discovered have not been adequately utilized for value addition to the economy.
Apart from the small volume used as reinjection feedstock in oil wells to boost oil production, the bulk of the resource have been wasted through gas flares, with their attendant environmental consequences.
Although the government has attempted to put a stop to the wastage, by imposing gas flare penalties, the action is considered too tepid to yield any meaningful value to the economy.
The operators find it easier to pay the penalty (about $3.50 per million standard cubic feet of gas flared) as prescribed by a Ministerial directive in 2011 than invest in the construction of gas harnessing and utilization infrastructure in the country.
The inconvenient truth is that the country has been losing several billion in revenues that could have accrued in the government coffers for not having a deliberate policy on the development of these resources.
Also, there are concerns about fiscal instability and unsustainable funding mechanism for frontier exploration, which have denied the country huge revenue prospects.
Apart from concerns about the high cost of operations due to fiscal system abuses, there are also difficulties relating to the operating environment; overlapping and ineffective governance framework.
Most operators build into their contract prices the cost they hope to pay to settle corrupt government officials. This often results in high final contract sums and huge losses to the government.
New PIB 2020
To create a framework that allows the government to earn more revenue not only from oil and gas exports but also operations, an Executive-sponsored PIB 2020 was initiated.
An oil and gas industry expert, Joe Nwakwue, a petroleum engineer, and Partner, Zera Advisory & Consulting, has described the PIB as a positive step to put the industry on the path to sustainable growth.
Under the PIB 2020, the governance and administration structures focused on establishing a framework for the creation of a commercially-oriented and profit-driven national petroleum company.
Also, the new law is aimed at promoting transparency, good governance and accountability in the administration of Nigeria’s petroleum resources; foster a business environment conducive for petroleum operations, and ensure sustainable prosperity within host communities.
One of the key pillars of the law is to help provide direct social and economic benefits from petroleum operations to host communities; enhance peaceful and harmonious co-existence between licensees or lessees and host communities, and create a framework to support the development of host communities.
Above all, the fiscal components contain deliberate policies to compel operators to conform with international best practices in their operations to bring more money in the government coffers.
The core principles guiding the preparation of the PIB 2020 are:
- to help the government earn revenues early from petroleum industry operations;
- simplify of administration of the industry, and
- ensure equity, fairness, competitiveness, transparency, predictability, responsiveness, best practice, sustainability and clarity of roles.
- establish a progressive fiscal framework that encourages investments in the Nigerian petroleum industry;
- balance rewards with risks,
- enhancing revenues to the Federal Government;
- provide a forward-looking fiscal framework based on core principles of clarity, dynamism and fiscal rules of general application;
- establish a fiscal framework that expands the revenue base of the Federal Government, while ensuring a fair return for investors;
- simplify the administration of petroleum tax, and promote equity and transparency in the petroleum industry fiscal regime.
To ensure separation and clarity between policy, regulation and commercial roles, the new law has identified the Minister of Petroleum as the policy-maker, owner and industry-driver charged with the responsibility of setting the general direction and supervision of the industry on behalf of the government.
For the regulatory role, the law envisages the creation of a Regulatory Commission or Authority charged with the responsibility of recommending to the government all upstream petroleum industry operating licenses to be awarded in the country.
The Commission will also serve as an independent supervisor and monitor of the technical and commercial regulations to ensure compliance to transparent and tight governance control practices.
The agency will also focus on midstream industry development to promote and optimize national resources and revenues.
For the commercial role, the new law foresees the establishment of a commercial entity, NNPC Limited, to own, operate and manage assets responsibly and profit-oriented on behalf of the government.
All investments of the new limited liability company will be through a self-funding mechanism that adheres to transparency, accountability and tight corporate governance, free from public burden, with its Executive appointments by the President.
The Board of the NNPC will be regulated by the provisions of the Companies and Allied Matters Act (CAMA) 2020.
How PIB can give government more money
The country’s oil and gas acreage sizes are reputed to be some of the largest in the world. With such sizes, international oil companies are able to sit on or hold on to their concessions for as long as they wanted without developing them and earning value for the country.
In designing the new fiscal system in the new PIB, the government wants every oil block allotted to any operator to have a definite term after which it can expire.
In the new PIB, a proper petroleum industry administration and licensing has been provided for.
Under the provision, there is an institutionalized open and transparent bidding process for the award of operating licenses to prospective investors.
No more discretionary award of oil licenses by the government without competitive bids by interested investors.
With this provision, the government would curb the attendant losses usually associated with the opaque licensing bid rounds.
Besides, the acreage sizes are drastically reduced, to make more acreages available for fresh entrants to the industry.
By so doing, the government stands the chance of earning more revenues through royalties and signature bonuses to be paid by new operators awarded oil licenses.
The new PIB has a provision that compels licensees to develop the leases awarded to them, or risk dropping them for others ready to do so.
There are consequences for failure to abide by the terms of such awards. This means only serious investors who would make frivolous bids would be allowed to participate in future bid exercises.
At the moment, the quantum of losses as a result of the restiveness in the oil-bearing communities as a result of years of neglect by the government is colossal.
The host community provision in the new PIB creates a framework to support the development of the host communities and foster sustainable prosperity within the host communities.
Apart from creating an environment to bring direct social and economic benefits from petroleum industry operations to the people, the provision will enhance peaceful and harmonious co-existence between the licensees/leasees and the host communities.
The fiscal framework in the new PIB has been reviewed significantly to bring more money into the government coffers. The focus will be on three key fiscal elements to earn value for the industry – royalty, tax and incentives.
Under the proposed framework, the single royalty system which the country is currently practicing along with other 12 other countries, or 76% of the world’s oil and gas producers, will change to a two-tier royalty system.
The single royalty system is based on operational terrains. This means the more difficult the terrain oil operations are conducted, the higher the incentive to compensate for the risks the operators take to be there.
Changing to the two-tier tax system means the country will join four countries, or 24 percent of the oil and gas producers in the world, that have already adopted this system in their domains.
Under the dual royalty system, apart from the terrain, incentives will be provided based on the level of production output and the prevailing price of crude oil in the international market.
The more an operator conducts exploration, finds and produces more oil, the more incentive it stands to receive from the government.
For royalty, the new PIB has decided not to make it flat in all terrains anymore. The objective is to make it flexible and progressive. The government believes a flat royalty regime is regressive.
The new PIB wants to make it less regressive, by designing it not to be based on terrain any longer, but on production and price, to enable government get more revenue if there is a windfall.
On tax, for many years, the industry has been operating a single tax system on petroleum.
Under this arrangement, company income tax (CIT) was 30%; Niger Delta Development Commission (NDDC) levy 3%; Tertiary Education Trust (TET) fund 2%; NESS 0.12%; petroleum profit tax (PPT) 85%; value added tax (VAT) 7.5%; Nigerian Content Development Fund (NCDF) 1%; insurance FOB 0.075%; weights and measures and several state local government taxes/levies.
The new PIB wants to break the tax regime into two – hydrocarbon and resource tax and corporate income tax allowance (CITA).
This will enable the oil companies to protect their income when profitability increases as a result of the incentive to remove them from cross-subsidization done over the years.
Cross-subsidization is the practice where the companies take money made from downstream operations to subsidize its operations in the upstream, and vice versa, and later find a way to deduct the cost in the form of a smaller tax.
If profit is made upstream, the company might pay 5% tax, and profit downstream, it pays 30% tax.
This is to protect the government revenue, so that every company registered in Nigeria will pay income tax, to correct the wrong perception that the tax rate in Nigeria is too big.
Onshore oil companies have been paying 5% after five years of operations, while deepwater operators pay 50% tax on their profits.
Production in onshore oil terrains, instead of paying 20% royalty, the company has been paying significantly less tax.
The new government’s thinking in the current PIB is to limit the incentives only to hydrocarbon development and allow the companies to leave with corporate income tax incentives when they are paying corporate income tax.
In the tax system, the government rewards efforts by the companies. The principle in the new PIB is to tax the companies but balance it by giving them generous incentives to soothe their pain.
The government is moving away from the incentive base. They are now talking in terms of production allowance tied to hydrocarbon tax.
The current practice caters to a spend-related investment tax credit (ITC), where the more a company spends to invest in projects, the more tax incentive it earns. This practice encouraged companies to inflate contracting costs on projects.
But the new arrangement for incentives is output-based on production volume, meaning tax allowances will be granted to the companies based on the volume of oil produced.
In the new PIB, production tax allowance (PTA) has been proposed for a minimum of 30% of oil price, or $3 for oil, or 50% of gas price, or $1.5, with 50-120% adjustment proposed depending on cost efficiency minimum.
For volume royalty, the current legal framework allows zero percent petroleum profit tax (PPT) up to a ceiling of 20% for oil, and 7% for gas.
The cost-efficiency factor is put at 20% operating expenditure price rate, with a reserve replacement incentive, and an additional production allowance of 50-125%.
The 30% tax inversion penalty based on cost price ratio contained in the draft fiscal policy has been removed in the new PIB.
What the PIB envisages here is for the prudent utilization of capital budgets and resources for projects as well as improved revenue earnings for the government.
The logic behind this is that the more oil produced would make more oil available for exports, and ultimately more revenue from the exports.
They move away from investment tax allowance (ITA) and investment tax credit (ITC), which is the most lucrative tax an investor can get, was necessary when the government wanted to attract operators to deep waters.
Under the new PIB, economic decisions will be based on investment performance, while incentives will be ways to enhance value on investment performance.
With the arrangement, the government is trying to persuade the companies away from what they have been enjoying for a long time, which was a source of huge losses to the government.
Under the old arrangement, there was a clause that said when the price of crude oil at the international oil market rises above $20 per barrel, the operators must come again for renegotiation of the agreement to review the percentage share of the profits.
But the government made a mistake and did not activate the clause in the early 2000s when crude oil prices climbed above the $20 per barrel threshold.
Therefore, all the years crude oil prices climbed to as much as over $140 per barrel as in 2014, the country lost the big revenue it could have earned if the percentage sharing formula between the oil companies and the government was reviewed.
The new PIB provides for the operators to meet with the government to review and agree on a new profit-sharing formula when crude oil price rises above an agreed threshold.
Under the two-tier tax system, the new PIB allows the regular company income tax allowance (CITA) and Nigerian hydrocarbon tax (NHT).
The NHT applies only to oil. Where applicable to condensate and natural gas liquids (NGLs), the tax must be on the oil produced from associated gas in an oil field.
Apart from not being applicable to associated gas, or non-associated gas and frontier, the NHT is not deductible for CITA.
NHT can be consolidated for each of the six classes of the hydrocarbon tax rates at new acreages at onshore locations, 22.5%; shallow waters, 20%; deep offshore, 10%; converted onshore acreages, 42.5%; converted shallow water acreages, 37%, and converted deep offshore acreages, 5%.
NHT is not applicable to frontier basins until the renewal of the lease.
On the other hand, the CITA rate of 30% will be determined on a consolidated basis for all upstream operations. The new PIB provides for the creation of separate regulators for midstream and downstream sectors.
Under the non-PIB legislation, companies will be further subjected to withholding tax on dividends (about 10%) and tertiary education tax of 2% of assessable profits.
The new PIB has abolished the 30% CITA of aggregate gas fiscal allowance in the current legal framework as recommended by the draft fiscal policy.
This arrangement limits resource incentives to NHT; allows normal payment of CITA, and increases revenue earnings to the government.
At the moment, the PPT rate is for between 50-85%. While the draft fiscal policy made a case for NHT of between 20-30% PPT for oil, there is no NHT tax for gas.
The NHT is subject to a cost-price limit of 65% of the gross revenues. Capital allowances and operating costs can be claimed up to this limit.
Where cost exceeds set limit in any month, such costs can be carried forward, until fully recovered. Any costs exceeding the cost price ratio limit upon the termination of upstream crude oil operations, which is not be deductible.
The current ITC and ITA do not apply to the NHT. Rather, production incentives per field crude oil production exclude production from primary recovery with or without initial injection wells.
Also, the PPT rate will change from between 5% and 20% tax for oil, and 5% and 10% tax for gas recommended in the draft fiscal policy, to between 2.5% and 20% tax for oil and 2-6% for gas.
Although the draft fiscal policy recommended 0.2% per dollar above $50 per barrel oil price capped at 20%, there is no such provision in the new PIB.
The price range in the current PIB is zero per cent royalty for oil price between zero to $50 per barrel, while $150 per barrel oil price will attract 10% royalty.
The justification for the proposal is to ensure companies pay as they produce, to allow the government earn more revenue from windfall situations.
The strategy is to ensure that when oil price rises above an agreed threshold contained in the operating agreement with the government, the companies must be invited for renegotiation and review of the percentage revenue earnings between them.
Besides, drilling costs facilities and other assets will be deducted as capital allowances at 20% per year, from the year the costs are incurred, except for the exploration wells and first two appraisal wells per field, which can be deducted 100%.
But, the new PIB proposes for a Petroleum Income Tax of between 40 and 65% for oil, and 50% for gas.
Cost Recovery to Price Ratio
For all conversion acreages, the production tax incentive is the lower of 20% of the fiscal oil price and $2.59 per barrel for any volume.
On new projects, the production tax incentive is the lower of 20% of fiscal oil price per barrel, or $8 per barrel for up to cumulative production of 50 million barrels from onshore acreages; 100 million barrels from shallow waters, and 500 million barrels from deep water.
About 20% of all fiscal oil price per barrel, or $4 per barrel thereafter.
The sequence of the Production Sharing Contract (PSC) is adjusted to an international concept applicable only to oil.
The PIB specifies that the cost under the production sharing contract (PSC) is limited to 70%, with the minimum profit oil share to the government based on cumulative production.
The rates are 5% for oil production up to 50 million barrels; 10% for production up to 100 million barrels; 15% for production up to 350 million barrels; 25% for production up to 700 million barrels; 35% for production up to 1,500 million barrels, and 45% for production above 1,500 million barrels.
Under the current PSCs, production sharing is calculated after deducting from the gross revenue the royalties, tax oil and costs.
Under the PSC for new acreages, the production sharing is calculated after deducting the royalties and cost oil. The NHT and CITA will be determined on the integrated revenues of the contractor being the cost oil and the contractor share of profit oil.
This arrangement will permit the consolidation of NHT and CITA to encourage reinvestment in Nigeria’s oil and gas industry.
Encouraging development of natural gas for power generation
The total fiscal package in the new PIB is designed to encourage investors to develop and produce natural gas in Nigeria, to generate more value for the economy.
For non-associated gas, the terms are 5% royalty (except for onshore gas that is exported) and CITA currently 30%. These terms also apply to the related condensates.
Although the royalty for associated gas is also 5% (except for onshore gas that is exported), there is NHT, but with a generous production allowance for associated gas and CITA.
There is no production sharing for gas, while gas costs can be taken as cost oil.
With Midstream Infrastructure Fund, there would be sufficient funding for ne downstream gas facilities development.
The PIB will permit producers, suppliers and consumer pipelines to transport their gas to different locations in the country.
The new law will provide the definition of a gas network code setting out the rights by any shipper to enter and exit gas pipelines operation, apart from implementing strong domestic gas delivery obligations for all producers.
There are several frontier oil basins in the country that have remained undeveloped because of incentives to stimulate exploration activities there.
The inability to develop these frontiers has denied the country the opportunity to add to the effort to increase the country’s oil output, and by extension, loss of revenue that could have accrued to the country by way of oil export earnings.
The new PIB provides favourable fiscal incentives, which consist 7.5% royalty and CITA for companies that venture into the area.
Under the frontier acreages, the new PIB, a petroleum exploration license may be converted to a petroleum prospecting license (PPL) prior to the termination of the license.
Also, frontier acreages in a PPL has 5 years as the initial period of exploration, which consists of only geophysical work.
A special Frontier Exploration Fund will be established to assists in providing funding to operators desirous of embarking on exploration for oil and gas in the area.
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