Nigeria: Selected Issues and Statistical Appendix

This Selected Issues paper and Statistical Appendix analyzes the key challenges facing Nigeria. The paper discusses issues and prospects in the oil and gas sector, provides basic information on the sector, and highlights the importance of strengthened governance. It describes the fiscal policy rules, which presents options for Nigeria based on the experience of other countries. The paper highlights that implementing a fiscal policy rule is identified as one possible way for Nigeria to stabilize public expenditures in the face of volatile oil prices.

Abstract

This Selected Issues paper and Statistical Appendix analyzes the key challenges facing Nigeria. The paper discusses issues and prospects in the oil and gas sector, provides basic information on the sector, and highlights the importance of strengthened governance. It describes the fiscal policy rules, which presents options for Nigeria based on the experience of other countries. The paper highlights that implementing a fiscal policy rule is identified as one possible way for Nigeria to stabilize public expenditures in the face of volatile oil prices.

II. Iissues and Prospects in the Oil and Gas Sector 1

A. Introduction

6. This section provides basic background information on the structure of the upstream and downstream oil and gas sector in Nigeria. In addition, it discusses key issues related to the prospects of the sector, the current fiscal regime, and, last but not least, governance and accountability in the sector.

7. Oil was discovered in Nigeria in 1956. From a modest start of producing about 5,000 barrels per day in 1957, Nigeria is today a major oil-producing country, the thirteenth largest producer in the world. Nigeria joined the Organization of Petroleum Exporting Countries (OPEC) in 1971 and is today the fifth-largest oil producer within the organization, with a quota of 1.787 million barrels per day (mbd). The state-owned national oil company, the Nigerian National Petroleum Company (NNPC) was established in 1977, and is a major player in both the upstream and downstream sectors. Gas resources are largely untapped, and Nigeria’s gas reserves place it among the top ten countries in the world in that category.

8. The oil and gas sector in Nigeria is today at a crossroad. After two decades of relative stagnation, oil and gas are poised for renewed expansion. New contracts (production-sharing contracts (PSCs)) have been signed for the exploration of offshore oil resources, accompanied by large investments from international oil companies. The development of the gas sector, encouraged through a number of substantial tax incentives, raises expectations of high export and government revenues. The main challenge for Nigeria is to manage the oil wealth effectively, so as to maximize its impact on economic growth and poverty reduction. While this paper focuses narrowly on the structure and prospects of the sector and the issue of governance, more general issues related to the design of appropriate macroeconomic policies in an oil-dependent economy like Nigeria’s are discussed in subsequent papers.

B. The Oil and Gas Upstream Sector: Endowment, Structure and Prospects

Resource endowment and structure

9. Nigeria is a country rich in oil resources. Crude oil reserves were estimated at 24 billion barrels in 2001. The reserve level targeted by the authorities for 2003, at 30 billion barrels, would be comparable to that of the United States, Libya, and Mexico, and would place Nigeria among the ten countries with the largest proven reserves (Figure II-1). At current production levels, these reserves would last for about 30 years.

Figure II-1.
Figure II-1.

Nigeria: Production, Proven Reserves, and Oil Prices

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Sources: Central Bank of Nigeria 2001 Statistical Appendix; and British Petroleum Statistical Review of World Energy (2002).

10. Nigeria’s total crude oil and condensate output had remained fairly stable from 1999 to 2001, around 2.2 mbd, out of which 85 percent was exported and the remainder allocated to the NNPC for domestic processing (Figure II-1). Given domestic refining capacity constraints, only about 51 percent of the domestic allocation was actually processed. The unprocessed balance was exported by the NNPC for cash. In 2002, following a reduction in Nigeria’s OPEC quota and periodic disruptions 2 to production, the daily production of crude oil (including condensate) is projected to be about 1.89 mbd.

11. The upstream oil sector is dominated by the NNPC, which holds a majority share (between 55 percent and 60 percent) in all six major joint-venture companies (JVCs) operating in Nigeria. The dominance of NNPC has historically reflected the public policy of using a state enterprise to develop domestic industries. In addition to these operations, the government of Nigeria has entered into PSCs with a number of private oil companies.

12. Nigeria produces and exports high-quality crude oil. Bonny Light and Forcados are Nigeria’s marker crude on the world market. The most prospective basin is the Niger Delta, accounting for almost all of the proven and potential reserves, and all oil production to date. Since 1990, Nigeria has encouraged exploration of deep offshore areas by offering new deepwater concessions. Estimates of recoverable oil in Nigerian deepwater areas range from 8 to nearly 20 billion barrels, and may increase significantly Nigeria’s current proven reserves.

13. In addition to oil resources, Nigeria has extensive gas resources. Nigeria’s current proven gas reserves (3.5 trillion cubic meters) place the country in the top ten in the world and its very large potential for new discoveries could raise further Nigeria’s reserves (Figure II-1). Production is still in its infant stage. Large volumes of associated gas are flared during oil production. Current projects in the gas sector target three potential markets: the export of liquefied natural gas to Europe and the United States; the processing of gas, currently flared, for use in the domestic market; and the building of gas pipelines to neighboring countries.

Prospects

14. A number of objectives have been set for the oil and gas sector by the current Nigerian government, including the following:

  • increasing production capacity, to 4 mbd by 2010;

  • raising reserves to 40 billion barrels by 2010, from 24 in 2002;

  • working within OPEC, and respecting OPEC quotas; and

  • eliminating gas flaring by 2008.

15. Prospects in the oil sector will depend on the strategy adopted to deal with two issues: (i) the increase in production capacity and the tension that this creates with the constraints imposed by OPEC quotas; and (ii) the diverging fiscal regimes under which oil companies operate, that is, the memorandum of understanding (MOU) fiscal regime (defined below) and the PSCs.

16. With regard to the first issue, while production (excluding gas) has been cut by 16.4 percent to 1.89 mbd projected for 2002 in compliance with OPEC’s reduced quota, Nigeria’s production capacity has grown to 2.6 mbd. Furthermore, the large investments in the sector will raise capacity at a much faster rate than the trend growth of 2 percent per annum demand. There is uncertainty in the oil industry in Nigeria with regard to how the government intends to address the rising potential excess capacity. The government has not yet clarified its future intention in this regard.

17. As to the second issue, the pressure to increase production will require that oil companies review the structure of their crude oil production. Currently, oil companies produce oil under two different fiscal regimes. These regimes are described in more detail in the next subsection. In brief, under the MOU fiscal regime, oil companies are liable for a government take, comprising petroleum profit tax (PPT) and royalty payments. Under PSCs, investment in exploration and development of new oil fields are recovered as “cost oil” when production starts, and then yield little revenues to the government until cost oil has been fully recovered.

18. As indicated above, the potential for a rapid increase in gas production is promising. The Nigerian authorities project that foreign exchange earnings from gas will surpass that from the sale of crude oil in the medium term. For the optimal development of the sector, the government will have to overcome some obstacles and address several key reform issues. First, is the challenge of eliminating gas flares. In 2002, up to 55 percent of associated gas was flared. The government has targeted 2008 as the date by which gas flares will be completely eliminated, and it is currently on track to meet that objective. A second and more challenging issue in developing the gas sector is the need to refurbish the power sector so that it can utilize effectively the gas output. Refurbishing the power sector will necessarily require the restructuring of the Nigeria Electricity Power Authority (NEPA) and the possible privatization of some aspects of power generation and distribution. Third, is the need to develop a domestic market for gas and gas by-products, including in Nigeria’s currently underserved regions. Fourth, is the promotion of investment in areas where gas utilization can lead to the substitution of imported products. Fifth, is the need to explore the potential for the export of gas to regional and extraregional markets.

19. At present, the development of the gas sector has centered on Nigeria’s oil activities, given the large volumes of associated gas produced. The main projects in operation are the Nigeria liquefied natural gas plant on Bonny Island and the Escravos-to-Lagos Pipeline System (ELPS). The range of further potential developments is wide, including utilizing gas in power projects, in liquefied natural gas (LNG) plants, in “gas-to-liquids” (GTL) and chemical industries, and exports through pipelines.3 To ensure a proper expansion of the sector, the government would have to establish an environment conducive to growth, backed by a global strategy for the sector. 4 In particular, the improvement and/or creation of infrastructure for the commercialization of gas and the institution of a solid legal and regulatory framework will be important steps.

C. Fiscal Regimes

20. Governments typically design fiscal regimes for extraction industries to maximize revenues while attracting investment in the sector (Box II-1). Changes in the oil and gas sector pose challenges to the fiscal regimes governing the sector, and to government revenues. To benefit from the prospects of expanding oil capacity and gas production, Nigeria will have to address two main issues. First, because of different fiscal regimes for oil companies under MOU and under PSCs, revenue flows may be affected by a shift in production from JVCs to PSCs. Second, the impact of tax and fiscal incentives on the development of the gas sector has important short-term fiscal costs and potential medium- to long-term revenue implications that need to be carefully assessed. In the short term, the MOU terms remain the main determinants of oil-related government revenues. In the longer term, as part of production will be shifted towards PSCs, PSC terms will become more important in the determination of government revenues.

Desirable Features of Fiscal Regimes for Petroleum and Gas Extraction

International best practices suggest certain desirable features of fiscal regimes in the oil and gas sector:

  • The government’s primary objective is to secure a major share of the resource rents, thus ensuring that the petroleum sector makes its due contribution to public revenues.

  • A second objective is that the fiscal regime for petroleum extraction should be progressive, that is positively correlated with project profitability. This suggests that the fiscal regime should be profit based and include incentives to contain costs.

  • Another objective is for the government to shift risks (volatility of oil prices and vagaries of petroleum extraction) to the major oil companies. One way to shift risk is to ensure early receipts of revenues, but this will make fiscal regimes less progressive.

  • The fiscal regime should provide incentives to increase production and productive capacity.

  • Finally, a fiscal regime should be stable, transparent, and easy to administer.

Memoranda of understanding

21. Under JVCs, the private partners are taxed under a fiscal regime known as the memorandum of understanding. Current estimates suggest that JVCs account for 98 percent of total oil production in Nigeria. The operations of the JVCs cover almost all of the allocated license areas, onshore and offshore.

22. Nigeria’s MOU terms are competitive in comparison with other oil-producing countries, such as Algeria, Angola, Indonesia, and Venezuela. The terms are satisfactory for both investors and government, because they provide adequate incentives to invest and transfer major shares of the project rents to the government.

23. Of the total crude oil produced by JVCs, 57 percent accrues to the government, equivalent to its average majority share in the joint ventures. Federation crude is then either exported, yielding significant inflows as crude oil sale receipts, or allocated to the NNPC for domestic use, yielding domestic crude receipts (see figures II-2 and II-3). Two other major sources of financial inflows to the federation are royalty and PPT payments by JVC partners. Other inflows include pipeline fees, rental fees, gas-flaring penalties, and natural gas export proceeds. In terms of outflows, cash call payments represent the funding requirements of the government to meet its share of the JVCs operating and capital costs. Payments for NNPC priority projects cover expenses such as maintenance and refurbishment of infrastructure.

Crude oil receipts

24. Government revenues from crude oil sales are largely exogenous, determined by Nigeria’s OPEC quota and international oil prices. However, actual production has tended to exceed OPEC quotas. Since January 2002, Nigeria has complied more closely with its OPEC quota and reduced its production of crude oil significantly (Figure II-4). Oil exports are also a function of domestic allocation: the larger the domestic allocation, the smaller the volume of crude oil available for exports. In 2002, domestic allocation was raised to 445,000 barrels per day, compared with 390,000 in 2001, thereby reducing further the NNPC’s volume of exports. The NNPC’s exports are priced on international markets as Bonny Light, with a small premium over the price of Brent. However, realized prices of the NNPC (or the National Petroleum Investment Management Services (NAPIMS), the marketing arm of the NNPC) are slightly lower than market prices (Figure II-5).

Figure II-2.
Figure II-2.

Nigeria: Decomposition of a Barrel Crude Oil 1/

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Sources: NNPC; and Fund staff estimates1/ Based on 2002 estimates.
Figure II-3.
Figure II-3.

Flow of Funds under the MOU

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Figure II-4.
Figure II-4.

Nigeria: Production, of Crude Oil and OPEC quota, January 1999—September 2002

(In millions of barrels a day)

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Sources: MNTC and OPEC.
Figure II-5.
Figure II-5.

Nigeria: Realized Export Prices Versus Bonny Light and Brent Prices, January 1993–August 2002

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Sources: NNPC; and IMF Commodity Price System.1/ Prices are entered with a month log to take into account the lag in payments of crude oil receipts
Royalty and petroleum profit tax

25. The MOU provides oil companies with the option of paying the lesser of the PPT and royalties under two different tax regimes. Under the first option, the PPT is calculated at a rate of 85 percent of profits. The royalty rates are 20 percent of onshore oil production, and between zero and 18.5 percent of offshore oil production, depending on depth. The total government take under this option is 88 percent (20 percent + 85 percent of 80) of the marginal dollar of crude oil revenue. For offshore oil, the government take is slightly lower. The second option—defined as the revised government take—calculates royalties and the PPT in a less direct fashion. Essentially, the PPT and royalty rates are applied to an adjusted tax base as follows. A tax reference price is arrived at by adjusting the realized price of oil by a factor that takes into account a guaranteed margin and a notional technical cost of producing oil. The margin is set at US$2.5 or US$2.7 per barrel, depending on the level of capital costs. Royalties are then calculated on the value of production using this tax reference price. Similarly, the PPT is calculated based on the tax reference price. As an incentive to reduce operating costs, a tax inversion penalty of 35 percent was introduced in 2000. This tax inversion penalty raises the tax liability of producers if technical costs exceed certain thresholds, while rewarding them with lower tax liabilities if costs are below these levels. Figure II-6 shows trends in dollar-related oil revenues between January 2001 and May 2002.

Figure II-6.
Figure II-6.

Nigeria: Main Oil-Related Government Revenues, January 2001-June 2002

(In millions of U.S. dollars)

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

Domestic crude receipts

26. The government receives payments from the NNPC for the domestic allocation of crude oil to NNPC. Crude is sold domestically at subsidized prices, with a two-month credit. Payments are made in local currency, using a subsidized exchange rate. In January 2002, in an attempt to move closer to market-determined prices, the government raised the price of domestic crude from US$9.5 per barrel to US$18, and the exchange rate from N 100 per dollar to N 110. Estimates of forgone revenues from the sale of domestic crude at subsidized prices are presented in Table II-1 below. In 2001, the estimated implicit subsidy reached N 250 billion (5.5 percent of GDP) and, for the first half of 2002, N 57.4 billion, in spite of the adjustment in the price paid by NNPC in January 2002. 5

Table II-1.

Nigeria: Implicit Subsidy to NNPC on Domestic Crude, 2001–02

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Sources: NNPC; Central Bank of Nigeria; and staff estimates.
Cash call payments and NNPC priority projects

27. Starting in 1995, gross proceeds from the sale of the NNPC’s share of oil have been transferred immediately to the Federation Account at the Central Bank of Nigeria (CBN). Accordingly, the NNPC’s share of monthly cash calls have been met from a budget appropriation. This mechanism was deemed necessary to increase federal government oversight over the distribution of revenues received by the NNPC. Under this system, the NNPC agrees to a work program with its joint-venture partners, and a cash call budget is approved as part of the federal budget process. Discrepancies between amounts approved by the NNPC and amounts approved by the budget, as well as delays in the budgetary process have led to the accumulation of cash call arrears. 6 These arrears directly affect output and raise the costs of petroleum operations in general. NNPC priority projects have also been funded out of the Federation Account. The Supreme Court ruled on April 5, 2002 that payments of cash calls as first charges on the Federation Account are unconstitutional. The decision of the Supreme Court has substantial implications for the NNPC, including the subsequent decision of the government to commercialize the operations of the NNPC starting on May 8, 2002. The current understanding is that the NNPC should receive the share of oil produced from each venture and directly provide its funding for payments of cash calls. Only the balance (i.e., net of costs) would then be transferred to the Federation Account. The NNPC priority projects are also to be funded directly by the NNPC.

Production-sharing contracts

28. Under the PSCs, the government retains the right to petroleum resources in the ground but appoints the investor as “contractor” to assist the government in developing the resources. The parties agree that the contractor will meet the exploration and development costs in return for a share of any production that may result. The PSC terms in Nigeria are based on a 1993-model contract, with a few exceptions that reflect earlier negotiations. All PSCs are contracts made between the NNPC and the investor. The PSC typically provides for a 30-year term, including 10 years for the exploration period.

29. The Nigerian PSC model offers advantages both to the government and the private investor:

  • PSCs allow the government to receive a significant share of production without imposing an obligation to commit budgetary revenues for the development of oil production (as opposed to required cash call payments under the MOU governing JVCs). The drawback for the government is the postponement of revenues from production.

  • PSCs allow the development of underdeveloped offshore areas without the government incurring the exploration risk.

  • PSCs provide the government with a framework within which it can encourage competition among existing and new investors.

  • PSCs allow the economic terms for an area to be varied without resort to amendment of fiscal legislation. PSC royalty and tax terms are fixed,7 but cost recovery and production sharing are negotiable.

30. For tax purposes, the production of oil can be defined as royalty oil, cost oil, tax oil and profit oil. Royalty oil is the first call on production under PSCs, and the rates levied on gross production vary from 16.67 percent for shallow-water areas (less than 200 meters), to 10 percent for inland basins and to zero when the water depth exceeds 1,000 meters. Almost all offshore PSCs signed to date cover deepwater blocks yielding low or zero royalty.8

31. Cost oil is the second call on production under the PSCs. All costs are expenses, except capital costs for tangible assets, which are recovered in equal annual installments over five years. Royalty oil is the only limit to the amount of gross oil that may be used for cost recovery. The absence of a cost oil limit is unusual in major oil-producing countries. 9 However, four characteristics of the Nigerian PSCs may limit revenue postponement. First, royalty oil is paid as soon as production starts. Second, capital expenditure is amortized over a five-year period, limiting de facto the volume of cost oil. Third, Nigerian PSCs are “ring-fenced,” that is, the area over which costs of one development can be offset against the revenue stream of another is restricted. This feature reduces to some extent the postponement of government revenues. Fourth, the government typically receives signature and bidding bonuses from prospective contractors. Signature bonuses in deep water have now reached significant sums (in the US$25 - US$40 million range) while amounts in inland basins are commonly around US$1 million or less.10 Production bonuses are payable at threshold amounts of cumulative production from the contract area and are larger for inland basins than for deepwater contracts.

32. Tax oil corresponds to the settlement of PPT liabilities. The PPT rate is 50 percent, lower than the 85 percent under the MOU for JVCs. 11 Tax oil and royalty oil are apportioned between the contractor and the NNPC in the same proportions that profit oil (see below) is allocated during the relevant accounting period, in order to replicate conventional tax calculation.

33. Profit oil is split between the contractor and the NNPC on a sliding scale related to cumulative production from the contract area. With some variations across contracts, splits for inland basins are generally more favorable to the NNPC than deepwater contracts. Overall, PSCs are relatively generous to the contractor throughout, as they recognize the high risks of exploration and development activity. However, as profit oil sharing according to cumulative production is regressive with respect to decreases in costs or increases in price, very large discoveries may yield returns so high to the investor that PSC terms may not be sustainable, particularly as profitability is not necessarily correlated to the scale of production. An alternative production sharing solution would be to link the NNPC profit oil share to a scale determined by the contractor’s achieved rate of return, on a field-by-field basis. This scheme would provide the investor greater protection from the discovery of less profitable fields, and allow the government to reap greater benefits from rich fields at high prices.

Implications of a shift in production from MOUs to PSCs

34. A shift in production away from MOUs toward PSCs may be expected because private oil companies have been investing large sums in offshore exploration and development and have a strong incentive to produce in order to recover their investment costs. The impact on government revenues needs to be carefully assessed by the Nigerian government, as revenues may be adversely affected in the transition period because of the deferment of tax revenues under the PSCs.

35. There is considerable uncertainty about the magnitude of the potential shift in production, its impact on cash call payments, the depth of the drillings, and the resulting royalty rates to be applied; as a result, the exact impact of a shift is difficult to assess. Based on a number of assumptions, the following simulation shows that the reduction in government revenues could be significant over the next five years. 12 The simulation assumes the following:

  • Production under PSCs is about 0.15 mbd in 2003 and rises to 0.34 mbd in 2007.

  • The average royalty rate is 1.6 percent, as most production (75 percent) is assumed to be deep offshore, yielding a zero royalty rate.

  • Given the absence of a cap on cost oil in Nigerian PSCs, but taking into account the amortization rule for capital expenditure, we assume that, during the first five years of production, 75 percent of all oil produced is exhausted through royalty oil and cost oil. The remainder is tax oil (PPT) and profit oil.

  • We also assume that cash call payments are reduced in line with the reduction in JVC production.

36. The simulation shows that government revenues in 2003 would be 9 percent lower under the above assumptions than if all production is assumed to be under memoranda of understanding, and up to 21 percent lower in 2007 (Table II-2). After the recovery of cost oil, the negative impact would gradually decline and PPT and profit sharing would increasingly yield substantial revenues for the government. The simulation also shows that the reduction in cash call payments compensates partly for the revenue loss.

Table II-2.

Nigeria: Impact on Government Revenues of a Shift in Production from Memoranda of Understanding to PSCs, 2003–07

(In millions of U.S. dollars, unless otherwise indicated)

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The current macroeconomic framework assumes that all oil production is done under memoranda of understanding.

For simplicity of presentation, the NNPC profit share from the operations of PSCs is included into crude oil sales.

Taxation of the gas sector

37. As noted earlier, Nigeria’s gas resources remain largely untapped. To promote development of the sector and to end costly gas flaring, the government has introduced a tax regime that combines penalties on flared gas and incentives for upstream development of the sector.

38. The structure of incentives is very generous by international standards. Gas producers have the ability to deduct operating and capital expenses against oil income. Investors in both the upstream and downstream gas sector also benefit from a five-year tax holiday, royalty exemption, and import duties/value-added tax (VAT) exemptions. The royalty rate is 5-7 percent, and exemption is granted if gas is transferred to downstream plants. Companies are liable for a 30 percent company income tax. Given the ability of investors to deduct all their gas expenditures against an 85 percent oil liability while paying only 30 percent tax on their gas revenues in the case of associated gas, the tax regime may result in posttax profits that are greater than pretax revenues.

39. While it is difficult to estimate accurately the impact of tax incentives on government revenues, it is evident that revenue losses are likely to be substantial. Such a favorable regime reflects the high priority given to development of the gas sector in Nigeria. A simple simulation based on a US$1 per barrel tax offset13 in the computation of PPT payments show that the reduction in revenue could be in the range of US$260 million in 2003, or about 0.6 percent of projected GDP (Table II-3).

Table II-3.

Nigeria: Impact of Tax Incentives on PPT Payments on Gas, 2003-07

(In millions of U.S. dollars, unless otherwise indicated)

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D. The Downstream Oil Sector

40. The downstream sector has been characterized by chronic inefficiencies and shortages of retail petroleum products. Such inefficiencies have led to a questioning of the overarching role of the NNPC in downstream operations, and of the corresponding commitment of financial resources (e.g. the implicit subsidy on domestic crude allocation). The government plans to deregulate the sector in a number of ways, including: the liberalization of petroleum product retail prices; the liberalization of imports of petroleum products; and the privatization of refineries. Deregulation would imply the elimination of price subsidies, in particular on domestic retail prices. In the context of the rapid expansion of the upstream oil and gas sector, a thorough restructuring of downstream activities is considered to be critical. Deregulation would also create a level playing field in the downstream sector, providing the incentives for the NNPC to improve the efficiency of its refining operations. The modalities of the commercialization of the downstream activities of the NNPC are yet to be clarified.

Structure of the downstream sector

41. The NNPC is a major player in Nigeria’s downstream oil industry. It has a monopoly in two main downstream segments—refining, and pipelines and storage depots—and is the main player in distribution and retail. The NNPC owns the country’s four refineries, and has a significant shareholding in the larger marketing companies. While the importation of petroleum products was recently liberalized, the gap between international oil prices and the regulated domestic retail prices does not allow for profitable imports of petroleum products.

42. The combined refining capacity of the four refineries is 445,000 barrels per day, equal to the current domestic allocation of crude oil to the NNPC. However, the below-average performance of the refineries has been responsible for the country’s reliance on imports to meet domestic demand. To complement the refineries, large investments have been made since 1979 in a network of pipelines and storage facilities for petroleum products in each of the major distribution zones of the country. Nominal pipeline capacity is 3,000 kilometers.

43. Distribution and retail facilities employ a fleet of road tankers to distribute petroleum products to retailers. The deterioration of the fleet and of the retail stations has made the distribution to consumers inefficient. Seven marketing companies account for about 60 percent of total petroleum product sales, with small independent operators accounting for the remaining portion.14

Issues and prospects

44. In recent years, petroleum product output has dropped well below nominal refining capacity. The domestic allocation of crude oil to the NNPC has been raised to nominal refining capacity in an effort to encourage domestic production of refined petroleum products. However, with about 50 percent of the domestic allocation being exported by the NNPC (Figure II-7) and a substantial portion of refined products for domestic consumption being imported, the objective is yet to be achieved. The net cost/benefit of diverting exports through the NNPC is debatable. The implicit subsidy on domestic crude (see section on fiscal regimes) works as a subsidy to cover the high costs of domestic refining operations and the obligation for NNPC to supply the retail market at below import parity prices. Further, recurrent shortages of petroleum products have encouraged black market activities. The gap between refining capacity and actual output is attributed to inadequate maintenance of plants and damage caused by sabotage, excessive fuel loss, and a suboptimal mix of products. In distribution and storage, capacity utilization is well below 50 percent.

Figure II.7.
Figure II.7.

Nigens: Domestic Allocation of crode Oil Refining Versus NNPC Exports, January 1999–June 2002

(In millions of barrels)

Citation: IMF Staff Country Reports 2003, 060; 10.5089/9781451828931.002.A002

45. Several options that are either being considered or implemented by the government to improve the functioning and efficiency of the refineries require private involvement/ownership to varying degrees.

  • Turn-around-maintenance (TAM) contracts have been awarded to international oil companies for the improvement of refining capacity. While hard data on the impact of TAMs are unavailable, there are indications of increases in capacity utilization. In the long run, such improvements might not be sustainable without major improvements in the management capacity of the refineries.

  • Consideration is being given to awarding management contracts while retaining public ownership. This solution entails the transfer of operatorship to the private sector.

  • Complete or partial privatization represents another option. The NNPC could retain a minority share of the refineries, which could be justified on the grounds of maintaining or building indigenous capacity.

  • Finally, the government has launched a program to issue licenses to private sector investors interested in the construction of new refineries.

46. The rehabilitation of pipeline and storage infrastructure would also be required to achieve the adequate delivery of retail products to the domestic market. Options similar to those suggested for the refining industry would be applicable to reform of the pipeline and storage aspects of the sector. All of these reform options will require some deregulation of the downstream petroleum sector, including a refocusing of the Ministry of Petroleum Resources and its agency, the Department of Petroleum Resources (DPR), which have responsibility for regulating the downstream sector.

47. Price regulation is an important area that needs reforming, including the following: the pricing of petroleum products delivered by the NNPC to the refineries; tariffs charged by the Pipeline & Products Marketing Co. Ltd (PPMC) to cover costs of transport, storage, and distribution; and ex-pump prices for retail products. The differential between domestic crude prices and international oil prices creates an incentive for the NNPC to divert its domestic allocation of crude oil to export markets. This is partly offset by the requirement that the NNPC meet any shortfall in the retail market by importing refined products. Domestic retail prices were also significantly lower than their import parity level in 2001. During the year, gasoline was sold at N 22 per liter, as opposed to an average import parity price of N 30.7 per liter15. The total implicit subsidy to the consumer is estimated at N 68 billion in 2001, Diesel and kerosene were sold at N 21 and N 17 per liter, respectively. In addition to raising the price charged for domestic crude sold to NNPC, the authorities raised the domestic retail price of gasoline by 18 percent, on January 1, 2002, The prices of diesel and kerosene were also raised by 24 percent and 41 percent, respectively, on that date.

48. There has traditionally been substantial public resistance to increases in petroleum product prices in Nigeria. In contrast to the price adjustments in January 2002, a price hike in July 2000 was rolled back in response to a successful general strike organized by the National Labor Congress that was accompanied by mass public protests. The Petroleum Product Pricing Regulatory Committee (PPPRC) was set up in January 2002 to ensure that retail prices remain in line with international oil prices. Under the existing arrangement, the PPPRC was expected to review and adjust, if necessary, petroleum product prices every three months. Since January 2002, despite the significant increase in international oil prices have not been adjusted as the government has been reluctant to do so in an election period. While gasoline was priced above import parity at prices prevailing on January 1, 2002, the de facto elimination of the import subsidy was short-lived with the subsequent rise in international prices.

E. Governance

49. The key issues in governance are (i) monitoring and controlling effectively costs of JVCs and of companies operating under PSCs; (ii) administering a competent tax administration system in the oil sector; and (iii) ensuring a transparent accounting of all oil sector flows between oil companies and the Federation Account, Ultimately, an accounting of the government’s uses of oil revenues will be essential, but this will require an overall strengthening of the public expenditure management systems of federal and state governments—an area that is outside the scope of this paper.

50. Weaknesses in the administration of the fiscal regimes in the oil and gas sector can lead to the undercollection of government revenues. Inadequate monitoring and ineffective tax administration also raise the risk of overestimating costs and, thus, lowering profit taxes. In addition, weaknesses in institutional capacity may lead to a failure to control cash call spending.16 Strengthened transparency and accountability would ensure that Nigeria receives maximum benefits from the oil and gas sector.

Production and revenue collection

51. With respect to the first two governance issues, responsibility for fiscal control of the JVCs is shared among three government agencies:

  • The National Petroleum Investment Management Services (NAPIMS), a subsidiary of the NNPC, holds the major equity interest in the JVCs (57 percent) and is responsible for the management of the government’s petroleum interests, notably the control and the monitoring of costs of companies operating through JVCs and PSCs. The objective of NAPIMS is primarily to maximize returns from the government’s upstream oil investments. While Nigerian costs per barrel are still low, compared with world standards, these costs have been constant over time, with little productivity gains. Improvements in internal auditing and monitoring could contribute to the reduction of costs. NAPIMS’s performance also affects government revenues by providing inputs for PPT and royalty calculations, principally the JVC costs.

  • The Department of Petroleum Resources (DPR) is responsible for issuance of licenses, royalty administration, and gas-flaring penalties. The administration of royalty payments is relatively simple, once price and volumes have been determined. Accountability and transparency in the DPR’s operation are reinforced by a secure payment system, with companies depositing royalty payments directly into the central bank. The main difficulty for the DPR has been the administration of the reserve addition bonus (RAB17), which was deleted from the 2000 MOU.

  • The Federal Inland Revenue Service (FIRS) is responsible for the administration of PPT and other direct taxes on oil companies, and also for the VAT. Within FIRS, the Petroleum and Pioneer Department (PPD) is responsible for the administration of taxes on oil companies. The PPT is assessed on the basis of profits arising in the calendar year, and paid in 12 monthly installments, with penalties for delays or nonpayment. Tax audits for the oil companies appears to be ineffective. Owing to the lack of trained staff, equipment, and institutional capacity, there is no annual audit strategy within the PPD. PPD audits are confined to collecting the total estimated tax and are mostly desk audits, in contrast with field audits, which would allow officials to physically examine the records and systems of companies. This situation poses a risk to government revenues, as the oil companies’ classification of costs for purposes of PPT calculation is becoming increasingly complicated and would require trained inspectors to investigate potential abuses.

52. In principle, the administrative roles of the three agencies are clearly distinguished. The same control and monitoring concepts are used by all three agencies and tie in well with industry accounting standards. This should ensure a system of cross-checks. At the revenue collection level, PPT and royalty are relatively straightforward to administer. Their structure has been long established, and the procedures have been tested over time. The corresponding legislation contains strong audit and information powers, magnified by a tough penalty system. Furthermore, the MOU was significantly simplified in 2000.

53. At the production level, the JVCs are governed by joint operating agreements, similar to those in use elsewhere in the world. As a dominant shareholder NAPIMS is in an especially strong position to enforce its rights. Three of the six JVCs contain other nonoperator partners, whose monitoring and control practices reinforce those of NAPIMS. Production is concentrated in the hands of a very small number of multinationals operating under constant public and government attention. As a result, firms are conscious that the continuation of their operations in Nigeria ultimately depends on the goodwill of the government. This situation provides incentives for firms to comply with the fiscal regimes governing their operations.

54. Nonetheless, governance in these areas can be strengthened in two key respects. First, institutional capacity is weak. Second, current operational procedures lag significantly behind international standards. Policy clarity and guidelines for sector development are needed in several key areas. These include upstream licensing, taxation and contracts, refining and product markets, and sector management. In this regard, the respective roles of the government, the NNPC, and the private sector will need to be clearly delineated. Third, given institutional weaknesses, the NNPC tends to substitute DPR as the main regulator of the industry, creating room for potential conflicts of interest.

55. Management of the oil sector could also be strengthened with regard to investment shortfalls, which are related in part to delays in payments of cash calls, subsidies and financial losses (in the downstream sector), the underutilization of refineries and product imports, and shortages. Improvement in the operational procedures related to administration of the fiscal regimes would require that urgent attention be paid to the availability of useful data, the frequency of audits, and the simplification of the current regime, which includes many special arrangements.

Accounting for revenue flows

56. As described above, the oil industry is very complex, involving a number of government agencies and industry players. This points to the need to develop an efficient and transparent accounting system for revenue flows and production data. Currently, there is a lack of coordination and of a reconciliation of data between government agencies. A World Bank review of oil sector flows for the period 1995-99 identified a series of revenue discrepancies: (i) the share of equity crude exceeded the documented disposal of crude oil, leading to an average annual shortfall of US$152 million; (ii) the realized price of NAPIMS was below market average, inducing an annual average shortfall of US$176 million; (iii) payments of royalty recorded by the DPR exceeded those recorded by the CBN by US$71 million; and (iv) a discrepancy between PPT payments reported by FIRS and the CBN is estimated at US$20 million a year over the period. Over the first six months of 2002, these discrepancies were reduced. Nevertheless, the discrepancies persist with respect to crude oil export receipts between the Office of the Accountant General (OAGF), the CBN and the NNPC, and with respect to PPT payments between the CBN and FIRS. Data on crude oil production differ significantly between sources, in particular when figures quoted in industry reports are compared with those published by the NNPC. According to the NNPC, the average crude oil production from January to September 2002 was 1.840 mbd, compared with the 1.955 reported by OPEC in its publications.

57. These differences do not necessarily point to deliberate misreporting of data. Nevertheless, they are likely to raise doubts about the transparency of the oil sector in Nigeria. While the discrepancies, in many cases, can be explained—for example, discrepancies may in some cases reflect timing differences and lags in payments, difference in the nature and coverage of the data reported—a transparent reporting of such explanations would strengthen the credibility of oil-revenue management.

Table II-4.

Nigeria: Oil-Related Government Revenues as Reported by Different Sources, December 2001 - August 2002

(In millions of U.S. dollars)

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Data reported for July by the CBN and OAGF account for changes due to the April 4, 2002 Supreme Court ruling and are not comparable to previous observations. 2002 average is based on the first six months.

On PPT and royalty payments, the CBN and the OAGF report consistent

Table II-5.

Nigeria: Production of Crude Oil as Reported by Different Sources, December 2001-August 2002

(In millions of barrels per day)

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OPEC reports on its website the average of production estimates from six industry reports.

I.E.A. is the International Energy Agency.

Strengthening transparency and accountability

58. Currently, information on oil sector revenue flows is not easily accessible. While NNPC accounts are audited, the reports are not publicly disseminated. A simplified, consolidated picture of the operations of all the companies operating in Nigeria would contribute significantly to transparency and accountability. The publication of credible data and audits is a necessary step to ensure credibility in the management of oil resources in Nigeria. Key aspects of this would include the following:

  • Data on liftings and sales of crude oil should be made available through monthly publication of production figures, audited and certified by an external and reputable auditor. Currently, operators report liftings and production figures to the DPR on a monthly basis. These are verified by the internal auditors of the operators and by the auditors of the joint operators. Consistent and reliable figures should be easily publishable. To ensure the credibility of the publication, good practice suggests that (i) the aggregation of the data at the DPR be carefully audited and certified; (ii) discrepancies between lifting and production volumes be accounted for; and (iii) publications be certified by a reputable external agent. In the spirit of the recent initiative by nongovernmental organizations, international oil companies could be encouraged to disclose information on revenue payments.

  • Liftings and sales of the federation share of crude oil should be monitored and include an audit of the COMD (Crude Oil Marketing Department) performance. Discrepancies may exist for both the volumes of crude oil sales and the realized price. The following is recommended: (i) the reconciliation of the COMD data on lifting and production volumes, with data provided by joint-venture partners; and (ii) the auditing of the performance of the COMD in marketing crude oil, with a special focus on procedures to ensure that crude oil is not underpriced.

  • Cost control and control of the use of cash call payments should be reinforced, in particular through the use of NAPIMS “value-for-money” audits. NAPIMS, as a major joint-venture partner, has extensive control and auditing powers. However, concerns have emerged about uses of cash call payments and the effectiveness of internal auditing. NAPIMS does not produce an annual audit of the activities of the JVCs and relies on the NNPC annual audit—which is not an adequate substitute. Internal audits should be improved, with an annual audit strategy from NAPIMS. This requires a substantial strengthening of the institutional capacity of NAPIMS. External auditors, transparently appointed, should complement the internal assessment. Those external auditors should have extensive experience with, and reputation in, the petroleum sector, and be familiar with the technicalities of petroleum accounting.

  • The administration of petroleum taxes should be strengthened through reconciliation, annual audits, and investment in institutional capacity building. The PPD has extensive control and information powers, and a set of applicable penalties. Although the administration of royalties and the PPT does not seem to raise major issues, improvements can be made in a number of areas. First, since information for royalty and PPT payments is provided in by the operating companies themselves, this should be reconciled with data provided by NAPIMS on both costs and production volumes. NAPIMS should submit its own profit estimates, to be reconciled with those of the JVC partners. Second, the PPD and the DPR should each define an annual audit strategy, with improved institutional capacity and effective tax audits for each company. In particular, the current practice of “desk audits” based on companies’ documentation should be replaced by effective “field audits.” Finally, as long as internal audit capacity is weak, internal audits should be complemented with external audits, which would follow the same rules as defined above (transparency, professionalism, competence, and reputation).

  • The Crude Oil and Other Revenue Reconciliation Committee is charged with reconciling accounts and estimates from the various agencies. However, no significant output has been produced by the committee. The committee should work to ensure the consistency of data produced for and by the sector and fiscal agencies.

F. Conclusion

59. The oil and gas sector in Nigeria is poised for rapid expansion over the medium term. In order to maximize the benefits of the sector for the economy, several challenges will have to be addressed by the government. These include the following:

  • Resolution of the tension between the objective of expanding capacity and the constraint of OPEC production quotas. While the government has stressed its commitment to OPEC, there is currently uncertainty in the oil industry with regard to how the government intends to address the issue of rising excess capacity in the sector.

  • Development of a global strategy for gas production. Earnings from gas production and exports are likely to exceed earnings from oil exports over the longer term. To realize this potential, the government will have to articulate a clear strategy for the sector, including the reform of the domestic power sector to take advantage of gas as a source of energy, the development of a domestic market for gas and gas products, and the promotion of exports of gas to regional and extraregional markets.

  • Management of oil production under different fiscal regimes. Given the significant investments in offshore exploration and the rising excess capacity, oil companies may be expected to gradually shift oil production away from the MOU fiscal regime to PSCs. This shift could reduce government revenues significantly in the medium term because of the deferment of revenues under PSCs. A key challenge will be to properly estimate the revenue implications of the evolution of production under the different fiscal regimes, factor these into the medium term fiscal framework, and manage the transition to PSCs, in consultation with the oil companies.

  • Deregulation of the downstream petroleum sector. While a start has been made in deregulating the downstream sector, critical reform areas remain. These include the full liberalization of petroleum product retail prices, the effective liberalization of petroleum product imports, and an improvement in the efficiency and privatization of refineries.

  • Strengthening of governance in the sector. Key areas to address include (i) the development of a transparent accounting of production and revenue flows in the sector, including a methodology to publish consolidated audited annual reports and accounts of the national oil company, as well as private oil companies; (ii) the reconciliation of revenue and production figures of different sources within and outside the government; (iii) cost control and monitoring within the sector; and (iv) institutional capacity to administer tax policies.

1

Prepared by Rodolphe Blavy.

2

periodic disturbances in some communities that feel aggrieved by oil operations have routinely affected oil production and export.

3

The utilization of gas in the power sector is promising, especially given the current insufficient level of electricity generation in Nigeria. The inefficiency of NEPA is such that small private power units provide more power capacity than NEPA. A number of proposals for additional LNG projects and GTL projects are under way. Finally, proposed pipeline projects, in particular, the West African Gas Pipeline (WAGP) and the Nigeria-to-Algeria Pipeline, may provide good platforms for exports to regional and extraregional markets.

4

The extensive work undertaken by the World Bank in the gas sector in Nigeria is a good reference for such a strategy.

5

The estimation does not take into account the two-month credit in domestic crude receipts.

6

When payments of cash calls to JVCs are delayed, JVC operators may borrow the equivalent amount and charge the interest to the NNPC. To avoid high interest expenses, NNPC has moved toward more timely payments of cash calls. However, there has bccn some controversy regarding pre1999 arrears. During the 1994-99 period, the military government accumulated significant arrears to JVC partners. The NNPC has recently estimated the stock of arrears for the period at US$500 million for the foreign exchange portion and at N 26 billion for the naira portion.

7

PSC royalty and tax terms have been fixed by Decree 9 of 1999.

8

In addition to royalty oil, contractors must pay surface rentals, at relatively low rates (within the range of N 200-500 per km2).

9

Some of the PSCs provide for recovery ofcosts of other blocks held by the contractor. While this feature creates a strong exploration incentive, it may induce a significant postponement of government revenues.

10

This difference may reflect relative prospects of the different regions and is partly offset by tougher production-sharing terms for inland basins on the grounds that onshore costs are likely to be lower.

11

Another difference is that the rate of investment tax credit or allowance is also 50 percent.

12

The simulation is illustrative, and sensitive to a modification in the assumptions. For example, the average royalty rate is calculated at 1.6 percent, under the assumption that 75 percent of the production is deep offshore. If we assume that 50 percent is deep offshore, while 25 percent is produced in shallow waters (the remainder being produced at intermediate depths), the average royalty rate becomes 4.4 percent, and the revenue loss to the government is smaller than estimated.

13

Tax offsets in the range of US$1-2 per barrel are common.

14

The main marketers and their relative shares are as follows: Total Elf (15.5 percent), African Petroleum (11.8 percent), National (8.5 percent), Mobil (7.4 percent), Unipetrol (6.8), Texaco (6.8 percent), and Agip (4.7 percent).

15

The calculation of the import parity price is based on the following variables: gasoline price FOB Italy, insurance and freight at US$25 per metric tons, and tax and marketing costs at N 8 per liter. The official exchange rate is used for conversion into domestic currency.

16

In this section, we focus on administrative controls and governance issues related to the operation of the JVCs, since they account for 97 percent of Nigerian oil production.

17

The 1991 MOU allowed a company to increase its after-tax margin by claiming the reserve addition bonus (RAB) as a credit against its PPT liability. The amount of RAB was based on additional proven or probable reserves in excess of the current year’s production.

Nigeria: Selected Issues and Statistical Appendix
Author: International Monetary Fund
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    Nigeria: Production, Proven Reserves, and Oil Prices

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    Nigeria: Decomposition of a Barrel Crude Oil 1/

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    Flow of Funds under the MOU

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    Nigeria: Production, of Crude Oil and OPEC quota, January 1999—September 2002

    (In millions of barrels a day)

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    Nigeria: Realized Export Prices Versus Bonny Light and Brent Prices, January 1993–August 2002

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    Nigeria: Main Oil-Related Government Revenues, January 2001-June 2002

    (In millions of U.S. dollars)

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    Nigens: Domestic Allocation of crode Oil Refining Versus NNPC Exports, January 1999–June 2002

    (In millions of barrels)