The failure of the Nigerian government to review the fiscal policies governing the exploration of oil in deep, offshore waters is costing the country a loss in oil revenue amounting to trillions of naira.
While other Organisation of Petroleum Exporting Countries (OPEC) is reviewing its laws in line with the realities of current international practices and crude oil prices, Nigeria remains stuck with old laws and regulations which have seen the country miss out on key sources of revenue even as it struggles to fund its annual budget.
For instance, in Nigeria, royalty rates are typically set as a percentage of value of oil produced and the size of the licensed area of production. Royalty rates range from zero percent to 20 percent in onshore areas under Joint Venture arrangement, while under Production Sharing Arrangement they range from zero to 12 percent. Royalty rates for gas production range from 5 percent for operations in offshore areas to 7 percent for operations in onshore areas.
The situation is not the same for other countries. Saudi Arabia, for instance, collects 85 percent royalty on commercial oil production and 30 percent on natural gas, while in neighbouring Qatar royalty rate is set by each development and fiscal agreement or joint venture agreement between the government and the company.
United Arab Emirates has no fixed royalty rate as taxes are currently imposed at the Emirate level on companies based on actual oil production in accordance with specific (but confidential) concession agreements, while Kuwait collects 50 percent royalty on commercial oil production.
In Russia, mineral extraction tax (also known as royalty) is charged on a fixed amount of $11 per tonne, multiplied by coefficients that vary by depletion of reserves and other factors.
Adeola Adenikinju, director, Centre for Petroleum Energy Economics and member of Nigeria’s Monetary Policy Committee (MPC), believes the current oil contractual agreement, most especially offshore production arrangement, is not favouring Nigeria
“In the past when oil price was very low, an MOU was signed to encourage IOCs, which ought to have been revised over 20 years ago. The MoU was supposed to encourage investment into offshore production, but with higher oil prices, that arrangement is shortchanging Nigeria,” Adenikinju told BusinessDay.
A study conducted by The Nigeria Extractive Industries Transparency Initiative (NEITI) in March 2019 revealed that Nigeria had lost at least $16 billion (N2.87 trillion at an average exchange rate of N179.65/$1 during the period) in 10 years due to non-review of the 1993 Production Sharing Contracts with oil companies.
“It would be difficult to recoup what has been described as lost by NEITI. The focus has to be on achieving a fair balance going forward,” Adeoye Adefulu, energy partner, Odujinrin & Adefulu, told BusinessDay.
As stated by NEITI, total production by PSC companies was below 100 million barrels per year between 1998 and 2005, while JV companies produced over 650 million barrels per year.
However, total production by PSC companies increased to 305.8 million barrels in 2017, representing 44.32 percent of total production. Meanwhile, JV companies’ production stood at 212.85 million barrels, representing 30.84 percent of total oil production.
Hence, reviewing the PSCs should see the Federal Government of Nigeria accumulate more revenue from deepwater crude production and exploration.
“A number of 1993 PSCs are already coming to the end of their term. This, therefore, presents the government a golden opportunity to renegotiate the terms of the PSCs,” Adefulu added.
While the JV, introduced in 1986, remains the principal contract model which typically governs onshore/shallow water projects for the purpose of exploration and production of resources, the inability of the NNPC to fund its equity participation in the JV made the arrangement increasingly unmanageable.
This gave birth to the PSCs introduced in 1993 to address some of the issues faced by the Joint Operating Agreement (JOA) and also to provide a suitable agreement structure for encouraging foreign investment in offshore domain.
The Federal Government recently revealed plans to reduce stakes in JV oil assets to 40 percent agreements with IOCs, as a way to shore up revenue.
Experts says the 1993 Deep Offshore contract was entered into at a time Nigeria, under the late military dictator Sani Abacha, was burdened by sanctions and needed money for key infrastructure projects.
Crude oil prices averaged $16.33 in 1993 and had risen to $17.44 by 1999, which was the last time efforts were made to amend the PSC decree to reflect that if crude oil price exceeds $20/barrel or 15 years after the initial contracts were signed, the agreement should be renegotiated in a manner that will be favourable to Nigeria.
Another peculiar situation in which old fiscal regime continues to shortchange Nigeria’s revenue is its cost of production. Nigeria’s cost of producing oil, at $22 per barrel, is still far higher than Iran, Iraq and OPEC’s kingpin Saudi Arabia’s.
According to data from energy industry consultant Rystad Energy, on average it cost Saudi Arabia less than $9 to produce a barrel of oil in 2018 while other OPEC countries like Iran and Iraq produce at about $10 per barrel which is below rival nations’.
Luqman Agboola, head of energy and infrastructure at Sofidam Capital, said after making so much money from crude oil in the past, Nigeria got carried away with corruption, inefficiency and security challenges while other countries were consciously reducing cost of production.
“One major factor affecting Nigeria’s situation is the Niger Delta security condition which naturally increases cost of producing a barrel by nothing less than $5,” Agboola told BusinessDay by phone. “If we become very efficient, Nigeria should be having a cost of production of between $12 and $15.”
Agboola explained that the second factor affecting Nigeria’s cost of production is the terrain.
“The likes of Iran, Saudi Arabia and Iraq produce in the desert which is naturally cheaper,” he said.
An oil explorationist who pleaded anonymity told BusinessDay that the main problem facing Nigeria are issues concerning multiple taxes, government policies and insecurity.
“Even Ghana and Tunisia are producing at $15 and $10, respectively,” the oil explorationist said.
Other stakeholders believe the inability of Nigerian government to collect royalty payments from deepwater oil operations has seen the country miss out on key sources of revenue even as it struggles to fund its annual budget.
In contrast India, for instance, collects 5 percent royalty on deepwater offshore production for the first five years of commercial operation, and 10 percent thereafter, while Egyptian national oil company, Egyptian General Petroleum Corporation (EGPC), pays royalties of 10 percent from its share of production to the state. In Kuwait, the government collects 15 percent royalty on all deepwater explorations and productions.
“The PIB would have been an opportunity to bring the system to international standard and make it more competitive which will benefit the government more,” Adenikinju said.
Nigeria has been on a perpetual voyage with the Petroleum Industry Bill (PIB), which is one of the most important bills ever to be contemplated in its history, in a journey that began 16 years ago with a lot of anticipation and promises. The bill is still stuttering through legislation after passing through four presidents, five presidential terms and five legislative tenures, yet there is little or no result to show.
DIPO OLADEHINDE
