Nigeria: The Price Of Delayed Oil Sector Reforms
As a mono economy, Nigeria depends largely on oil proceeds to fund her government, service debts, maintain a stable exchange rate, provide infrastructure and better life for the citizens. However, meeting these responsibilities have become increasingly difficult due to shrinking revenue.
As a result, the country’s 2019 budget deficit is N1.64trillion, as approved in the Medium-Term Expenditure Framework (MTEF) and Fiscal Strategy Paper (FSP) last Tuesday by the Senate. It is expected to be funded by borrowing. Already Nigeria’s foreign debt stands at $25.27 billion, with a domestic debt of N16.63 trillion as at December 31, 2018.
Nigeria has over the years failed to take full advantage of her natural resources while the commodity remains of value. While the world is moving on to technological development that would soon make oil not much sought after, Nigeria remains stuck on conversations around reforming her oil and gas sector. Rather than urgently deploy policies capable of breathing new life into the industry, maximize the potentials and ultimately diversify away from oil, the country has been stuck on a spot. Simply drafting an oil sector reform bill and making it a law, has taken 18years, and counting.
Perhaps the government fail to realize that Nigeria is no longer the darling it used to be in terms of resource endowment. Although the country continues to pride herself as Africa’s largest oil producer, the reality is that the dynamics are fast changing and we may not retain that title for much longer if the right steps are not urgently taken.
Recently in Lagos, at a workshop on petroleum sector costs, e360 learnt that for our national plan to sustain production at 2.4 million barrels per day by 2017, required investment needed to grow from about $0.94 billion in 2011 to about $7 billion by 2017. To maintain same production figure and meet the national aspiration for oil and gas, experts say about $24 billion investment would be required by 2025. Additionally, the unit cost production needs to drop well below $20 per barrel, for Nigeria to realize good revenue from oil in view of the current price volatility.
Meanwhile, considering that country hasn’t issued exploration licenses in years, keeping up with the target might be a huge challenge a little further down the road. Recently the CEO of Total, Patrick Pouyanne, called on the Nigeria to issue exploration licenses, expressing worry over the dormant state of the industry in terms of exploration. While that call is in order, the question then would be, how reasonable it is to enter new licensing rounds on existing laws which are archaic and causing Nigeria serious revenue leakages.
For instance, it is on record that Nigeria has lost an estimated $18 billion due to the obsolete Deep Offshore and Production Sharing Contract Act 1993. A major section of the Act gives incentives for deep offshore drilling to oil companies such that those drilling beyond 1000 meters paid 0% royalty until such as time as the price of crude went beyond $20. While the $20 benchmark has been crossed since 1993, the federal government has failed to activate this clause resulting in substantial loss of revenue.
To put this into proper context, the loss arising from the obsolete 1993 PSCs alone could have funded the entire Federal Government budget in 2015, according to a Policy Brief by the Nigeria Extractive Industries Transparency Initiative (NEITI), which estimated $16.03 billion as a low threshold loss to outdated PSCs. The figure it said can also fund 55percent of the federal government’s proposed budget for 2019.
The estimated cost of the Port Harcourt – Maiduguri Rail Line is between $14 billion and $15 billion, which the estimated losses would conveniently fund. It is also important to note that the estimated cost of the 3,050MW Mambila Power Plant is $5.72 billion, while the estimated cost of the Ibadan-Ilorin-Minna-Kano Standard Gauge Line is $6.1 billion. The combined cost of these projects is $11.82 billion, which is less than the estimated losses.
Also worthy of mention is the fact that the estimated losses are equally sufficient to fund the combined costs of the Calabar-Lagos Rail line ($11 billion), Fourth Mainland Bridge ($1.4 billion), Badagry Deep Water Port Complex ($1.6 billion), and Lekki Deep Seaport ($1.2 billion). If these critical projects could have been delivered by an amount equal to the estimated loss from one stream, one can only imagine the huge cost Nigerians are paying for the delay in reforming the oil and gas sector. The number of hospitals, schools, bridges and roads that revenues lost to the several outdated contracts and expired Memorandums of Understanding (MOUs) still in force, could have provided, can only be imagined.
Another dimension to the narrative are losses incurred due to the difficulty of operational terrain. These include cost premium on materials and services as a result of Niger Delta security situation, production deferment due to security situation, including deferred production due to schedule delays on projects, investments in alternative evacuation – resulting from sabotage of pipelines and export facilities. All of these drive up costs of production in Nigeria compared with other terrains.
To maintain the same level of production, higher investments levels are required in operating cost. For instance data shows that while it cost an average of $24 and $21 to produce a barrel of oil in Libya and Algeria respectively, it costs an average of $33 in Nigeria. In Iran, it costs an average of $13, and $11 in Iraq. In Saudi Arabia it is an average of $10, and Kuwait with the least production average cost at $9 per barrel.
Although the Nigerian government currently has a policy to reduce production cost in Nigeria by $10 to remain highly competitive, the goal might be difficult to achieve without necessary reforms which would be instrumental to drive down the costs.
The key objectives of the proposed petroleum policies and fiscal reform bills is to create a single regulator for the petroleum industry, exit current cash call arrangement by moving the current un-incorporated Joint Ventures to Incorporated Joint Ventures, make petroleum host communities critical stakeholders so as to ensure unhindered access, and eliminate crude theft, sabotage and other illegal activities to ultimately reduce overall cost.
Others are to deploy appropriate fiscal tools to incentivize cost reduction such as introduction of Cost Efficiency Factors (CEF) into the tax code, overhaul of the current procurement regime, encourage data sharing by stakeholder agencies and introduction of a progressive tax structure that is enshrined on fiscal rules of general application.
In addition to the above provisions, experts recommend that unit upstream capital and operating cost be subject to appropriate benchmarking by the industry regulator. These benchmark data should then be used as a basis for setting cost targets for the industry, and as a basis for cost acceptability for tax recovery. To give legal backing to the above, experts advocate that subsection (1) of section 6 of the PIFB be amended to include reasonability as one of the yardsticks for cost to be admitted for tax deduction.