Nigeria Natural Gas: A Transition from Waste to Resource

Written By:  M. J. Economides, A. O. Fasina & B. Oloyede

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The decree issued by the Nigerian government to stop the flaring of natural gas in hydrocarbon exploration and production (E&P) activities is an effort to realise commercial benefits from the nation’s huge gas reserves. Nigeria has more than 250 oil and gas fields, with about 2,600 producing oil wells and a total oil production of about 2 million barrels per day (mb/d). The proven oil reserves are estimated at 27 billion barrels while the proven gas reserves, consisting of about 50 per cent associated and 50 per cent non-associated gas, stand at 124 trillion cubic feet (tcf), or about 21 billion barrels of oil equivalent. This is one-third of Africa’s total gas reserves. Nigeria is the ninth largest gas producer in the world and a major potential gas supplier. The proved, probable and possible gas reserves are about 300 tcf.

Oil provides annual revenue of $10 billion for Nigeria and accounts for 90 per cent of the nation’s total export earnings and 57 per cent of the gross domestic product. In 2000, the Nigerian president declared that “within four years, revenue from gas will not only be substantial but will nearly be equal to that of crude oil.” Although the plan is ambitious, if the government pursues it rigorously, it has the opportunity to generate close to $10 billion per year from sales of natural gas produced in the country in the next few years.

In the past, E&P efforts have concentrated on oil while the associated gas has been treated as a waste. As of 2002, Nigeria has produced approximately 19 billion barrels of oil since production started in 1960. Total gas production is currently estimated at approximately 1.9 tcf per year, with an average of 850 billion cubic feet (bcf) per year being flared. The amount of gas flared would result in equivalent annual revenue loss of $2.5 billion at an average gas price of $3 per thousand cubic feet (mcf). Based on our own estimation of gas production, the country has flared an amount of gas capable of paying off its national debt, which stands at $31 billion. If the production rate is maintained, Nigeria has the capability to produce gas for the next 70 years based on the production-to-reserves ratio. This is a larger production-to-reserves ratio than for oil.

The natural gas price in Nigeria is currently very low, ranging from $0.20/mcf to $0.65/mcf. Domestic demand for gas is principally from the power sector and the fertilizer, aluminum smelting, steel and cement industries. To realise value for natural gas produced in Nigeria, a substantial export market must be found.

The worldwide proven natural gas reserves are estimated to be about 5,300 tcf, while the world gas demand is 225 bcf per day, giving a production-to-reserves ratio equivalent to 60 years of production. The United States, Western Europe and Japan account for half of the world’s gas consumption, but between them, they account for less than one-fifth of the world’s natural gas reserves. They rely on imports from gas-producing countries to meet their demand. Gas supply to the consuming countries is mainly in the form of pipelines and, increasingly, liquefied natural gas (LNG).

LNG trade is economically attractive at a minimum gas price range of $2.50 to $3.50 per mcf. The gas price has not been in this range during most of the past 10 years, thus discouraging the LNG market. More important, because of the scarcity of trade, there has not been an internationally and widely accepted price for natural gas, as there has been for oil.

In the last three years, these trends have significantly reversed, as forecasts of natural gas demand have greatly outpaced the supply, and prices have spiked at over $10/mcf. With demand already rising, coupled with depleted gas reserves in the consuming countries, the gas price is likely at least to stabilise at a price range that will make the LNG trade economically attractive for a long time to come. Most probably, natural gas prices will be maintained considerably above this range until LNG becomes a reality in a massive way. This position was recently buttressed by the pronouncement by U.S. Federal Reserve Chairman Alan Greenspan.

Nigeria has been targeted clearly as a major oil producer for the next decade, especially from the offshore blocks, but its potential for gas production has been underestimated thus far. The quota from the Organization of the Petroleum Exporting Countries (OPEC) for the member countries regulates oil activities. Although OPEC has not set specific quota for gas production from member countries, constraint on oil production limits the amount of associated gas that can be produced daily. This constraint can be overcome if discoveries of non-associated gas are made. Recently, a total of 13 tcf of non-associated gas reserves were discovered in Bosi and Doro deepwater blocks at a depth of less than 4,500 feet.

The OPEC World Energy Models forecast that world oil demand will rise from 76 million barrels per day in 2000 to 103 million barrels per day in 2020. In spite of this large increase, the oil share of energy demand will decline from 41 per cent to 38 per cent, while the gas share of world energy demand will rise from 22 per cent to 27 per cent. Some suggest that gas utilisation would be much higher than the conventional estimates, predicting instead that by 2020, gas would account for 45-50 per cent of the worldwide energy demand while oil will be reduced to 25 per cent.

In spite of such range differences, there is universal agreement in all forecasts that gas utilisation will increase substantially, causing a decrease in the oil share over the next two decades. This provides a major incentive for Nigeria to produce much more natural gas and export it as LNG to places of ever-increasing demand.

Nigeria’s Natural Gas Potential

Nigeria’s natural gas reserves are found in relatively simple geologic structures along the country’s coastal Niger River Delta and the offshore blocks. Other prospective hydrocarbon-bearing basins have yet to be fully explored, including the Benin basin, Anambra basin, Benue trough, Bida basin and Chad basin.

Most of the proven gas reserves are found as associated gas in the Niger Delta basin, while the majority of the non-associated gas has been discovered in the offshore blocks. The proven gas reserves of Nigeria are 124 tcf, and 90 per cent of hydrocarbon reservoirs in Nigeria contain potential commercial volume gas-caps. Lack of interest in gas exploration in previous years has resulted in commercial reserves of gas being locked in. This situation will improve with increased efforts to drill for gas. If the theory of finding huge gas reserves in deepwater fields holds true for Nigeria, then there are surprises yet to be discovered in the huge deepwater region.

On the basis of reserves, current gas production rates and the anticipated additions from currently developed projects, Figure 1 shows a forecast of Nigerian gas production for one decade, from 2003 to 2012.

Accessibility and Infrastructure
Nigeria has often been referred to as a country with large reserves of “stranded” gas. The current infrastructure for the use of gas inside Nigeria includes a transportation network and some gas utilisation projects.

When the producing oil field is located onshore, whether land or swamp, the producing well is tied to a flowstation. A flowstation serves as the collection centre for many wells, and the facility is used to separate gas from the remaining hydrocarbon fluid. Much of the separated gas is flared at the flowstation; some is sent to the gas-gathering system for treatment for domestic or export use. Gas-producing fields are connected directly to processing plants for treatment.

However, if the well is located in shallow waters, it may be tied to a fixed platform where the gas is partially separated from the remaining hydrocarbon fluid. Developed wells in shallow waters have recently been tied to floating production facilities where full treatment occurs for export purposes. Offshore wells are developed with the use of floating production and storage facilities, which enable full treatment and storage of the hydrocarbon for immediate export.

Operators have embarked on the construction of a gas-gathering system that will collect the gas that had previously been flared at the flowstations. The collected gas will be piped to LNG facilities for treatment and export. Associated gas produced from floating production facilities that are located in the shallow and deepwater areas will be connected via the proposed new offshore gas-gathering system and sent to the nearest LNG facility for treatment and export. The current thinking is either to develop major offshore non-associated gas fields with floating LNG facilities or to pipe the gas to an LNG facility located at the shore. The
economics of such big projects is still under review.

Internal gas utilisation includes current and proposed projects. An existing pipeline system supplies treated gas to industries in the southern part of the country. Natural Gas Corporation (NGC), a wholly owned subsidiary of Nigeria National Petroleum Corporation, operates a large share of the transmission network located in the south. Several large gas export projects have been initiated and new ones are planned to ensure that revenues are generated from gas resources and gas flaring is eliminated. The proposed West Africa Gas pipeline project, for example, is expected to supply gas to Nigeria’s neighbors, Benin, Togo and Ghana, for the purpose of power generation.

A recent proposal is to construct a trans-Sahara pipeline that will deliver Nigerian gas to Europe. Capital investment for the pipeline was put at roughly $9 billion with an annual operating cost of $749 million. The project projected a positive internal rate of return at a gas price of $1.50. One of the major challenges for the project, however, is that the proposed pipeline route passes through four countries with difficult logistical
and political conditions.

Potential Market for Nigerian Gas
There are two potential growth markets for Nigerian natural gas: domestic to a lesser degree, and export to a much larger scale. Domestic uses involve power generation, the cement industry, iron and steel plants, petrochemicals, aluminium smelting and distribution for other industrial uses.

Power sector: The largest single domestic consumer of natural gas is the Nigerian Electric Power Authority (NEPA), accounting for 70 per cent of the gas consumed in the country. The expected growth for power demand for a developing nation like Nigeria is estimated at 8 per cent per year. Power generation and supply in Nigeria is grossly below demand, thereby resulting in underdevelopments in every facet of life. NEPA generates power from two sources: the hydroelectric power generation plant in the Kainji dam and gas-fired electric generation plants located throughout the country. The manufacturing industry is paralysed from erratic supply of energy. Efforts to remedy the situation will propel the country in the path to development and realisation of other resources that are dependent on energy supply.

Cement: Non-gas-fired cement is not competitive with the export market because of its production cost. Nigeria has eight cement plants, only three of which operate above one-quarter of their installed capacity. Production from these three plants meets only 50 per cent of local demand, while the remaining cement is imported. Expected growth in this industry can only happen if local producers can reduce their production costs efficiently and competitively. This can only happen if gas can be supplied at a relatively low cost to other gas plants in the country.

Fertilizer: The Nigerian application of fertilizer averages 13 kilograms per hectare, one of the lowest in Africa. There are opportunities to expand fertilizer utilisation beyond the 800,000 tons per year currently consumed. Fertilizer demand is projected to increase by 6 to 7 per cent per year over the next 20 years.

Steel: This sector has been dysfunctional for years but has the capability to pick up with change in government policies and privatisation. The two plants owned by the government have the capacity to produce 1.8 million tons of steel per annum but are currently producing only 0.4 million tons. There is a chance for growth in this sector since the demand for steel in the country is currently satisfied by imports and other private-sector mills.

Other sectors: Other sectors that utilise gas are the small-scale industry and residential consumption of bottled liquid propane gas (LPG). The use of compressed natural gas (CNG) as a substitute for LPG was hurt by the cost of developing the CNG infrastructure. A study that was done in this area indicated that domestic consumers would not be able to afford the cost of purchasing CNG. The anticipated growth case in this small-scale energy demand area is around 7.5 per cent per annum.

The projected growth of the domestic market for gas utilisation depends on a number of factors: the enabling environment that allows the public and private sector to invest in the industries, regulations that will encourage oil multinationals to invest in gas-utilisation infrastructure like energy generation, changes in some government monopoly policies and a transparent structure for gas pricing in the country. Figure 2 shows the current and projected utilisation capacity of natural gas for domestic use.

Information derived from Figures 1 and 2 indicate that Nigeria has a capacity to export more than 2 tcf of gas per year for a number of years, in spite of the projected increase in domestic demand.

The export market for Nigerian natural gas started in 1999 after the construction of the Bonny LNG plant, located in Finima, Bonny Island. It was built primarily on reclaimed land. Developed to be one of the world’s major exporters of LNG, the plant site has a capacity to accommodate up to six trains. The base project with two trains was completed in August 1999. An expansion project with one train and associated LPG facilities was finished in November 2002. Development work on the fourth and fifth trains commenced in 1999, with start-up planned for 2005. Nigeria LNG currently provides 7 per cent of the world’s LNG requirements. This figure will rise to 13 per cent when the fourth and fifth trains come on stream, making the country the
world’s third largest exporter of LNG.

Nigeria Gas for the United States Market
For Nigeria to realise an export market price of $3.50, a greater percentage of the volume of gas exported must find its way to the U.S. market, which is already in short supply. We estimate that the U.S. market will be able to absorb 1 tcf/annum of LNG from Nigeria. This will follow the trends of oil export, remembering that the U.S. is also Nigeria’s largest market for crude oil.

Projections indicate that the U.S. gas demand between 2000 and 2020 will grow by 60 per cent, and that this growth can be satisfied almost exclusively by imports. The high increase in gas price in the last couple of years confirms that the supply of natural gas in the U.S. is not meeting the demand. Nigeria started supplying the U.S. with LNG in 2000 with a total supply of 12 billion cubic feet (bcf), compared to Algeria, which supplied 44 bcf. Considering the U.S. future needs of LNG, Nigeria can increase its gas supply to the U.S. for a good price.

Cost of Exporting Nigerian Natural Gas
Development of gas infrastructure and gas utilisation projects in Nigeria is very capital intensive. To obtain commercial benefits from natural gas exported from Nigeria, the price of gas in the export market must be greater than the cost of production, liquefaction, transportation and regasification. The most critical of these costs is that of liquefaction, which in most cases represents between 55 and 75 per cent of the total cost.

To appreciate the economics of gas development projects in Nigeria, we have used two classifications based on the source of gas:

• non-associated gas produced from offshore fields
• associated gas produced from onshore and offshore fields

We have calculated the gas activation index and equilibrium price for the production and liquefaction phases, and we used published data for transportation and regasification. The gas activation index as used here is defined as the capital investment required to produce and process 1 mcf/day of gas for export as LNG.

Cost of Production of Non-Associated Gas in Nigerian Deepwater Fields
The majority of gas produced in Nigeria is associated gas. Commercial reserves of non-associated gas have recently been discovered in the deepwater region. There are two plausible methods for developing the deepwater non-associated gas fields:

• construction of floating LNG facilities
• gas-to-shore approach

Figure 3 shows the capital costs involved in deriving the activation index and equilibrium price for these two development scenarios. It is assumed that the field is capable of producing 1.35 bcf/day of gas, using 30 wells with a plateau production for the first five years, and having a production life of 25 years. Installation costs are included in the estimates.

Based on the calculated activation index (AI) values in Figure 3, if we assume a five-year economic life, tax rate of 30 per cent, operating expenses of 20 per cent and discount rate of 10 per cent, we obtain an equilibrium price of $1.10/mcf for natural gas production. This is based on development with floating LNG and $1.60/mcf if the gas-to-shore method is used. The cost of production based on the floating LNG method appears cheaper, bearing in mind that no one has yet used this method.

Cost of Production of Associated Gas from Onshore and Offshore Fields
Associated gas is collected from the flowstations via the gas-gathering systems that are developed in the Niger Delta area. The gas is transported to the LNG plant for export or for distribution via the gas-processing plants for domestic use. In analysing the project economics of associated gas production, we have used the conditions obtained from the associated gas framework agreement developed by the oil industry for government approval in 1992:

• All investment necessary to separate oil and gas from the reservoir into useable products is considered part of the oil field development;
• Capital investment for facilities to deliver associated gas in useable form at utilisation or designated custody transfer points will be treated for fiscal purposes as part of the capital investment for oil development;
• Capital expenditures will be depreciated over five years at 20 per cent per annum for the first four years and 19 per cent in the last year;
• The capital allowances will be offset against oil income at a tax rate of 85 per cent; and
• The operating expenses for delivery of gas for commercial use and revenues from sales of gas, and products extracted or derived from the gas, will be treated under the fiscal terms for gas producers – that is, at a tax rate of 40 per cent (now 30 per cent).

To calculate the activation index for associated gas up to the point of conversion to LNG, we obtained the capital cost for the upstream activities (notably the cost of providing the gas-gathering system) and the capital cost for liquefaction. The capital costs, excluding well costs, of some of the gas-gathering projects in the Niger Delta are presented in Figure 4.

Almost all the values obtained are higher than the highest AIs obtained for most commercial gas projects in the United States. The highest AI value computed for a U.S. gas project is $2,760/mcf/d. It would appear that gas produced from these projects is not economically attractive for export. For example, Sapele AGG, with an AI value of $6,692/mscf/d, returns an equilibrium price of $10.34/mscf of gas.

However, the reason the production of associated gas in the Niger Delta may be profitable despite these capital-intensive projects is that a large part of the capital cost is hidden within the project economics of the accompanying oil production as stated in the framework agreement; otherwise, the projects will not be profitable for the operators. A newcomer planning to explore for gas in the onshore fields needs to be aware of this situation. Producing gas that requires a gas-gathering system in the onshore area may be uneconomical, unlike the typical offshore single commercial reserves.

Operators now charge a tariff of $0.30/mcf to supply feed gas to the Bonny LNG plant. This price returns an AI of $194/mscf/d, which is far lower than the values shown in Figure 4. Stranded gas in Nigeria is obviously much cheaper than gas drilled on purpose.

Thus, producing Nigerian onshore natural gas for export may not be as cheap as some now perceive. Much of the capital costs for the gas-gathering projects are embedded in the capital costs associated with oil production.

Cost of Liquefaction

The cost estimate of constructing an LNG plant that will process 1.35 bcf/d of natural gas – either with a floating LNG or onshore LNG plant – is put at $2.80 billion. This cost estimate compares favorably with the cost of the recently completed LNG plant in Nigeria. The first phase of the Bonny LNG plant, which cost $2.5 billion, is expected to treat 900 million cubic feet (MMcf) per day of feed gas. The cost estimate gives an average AI of $2,074/mscf/d and an equilibrium price of $2.35/mcf for just the liquefaction process. Although some believe the cost of liquefaction could be between $0.80 and $1.00/mcf, our economic model indicates that this figure is too low for the liquefaction process in Nigeria.

Cost of Transportation and Regasification

The cost of transporting LNG from a place like Nigeria to the United States and the cost of regasification has been put between $0.80/mcf and $1.05/mcf of natural gas. If the feed gas can be made available at the current tariff price of $0.30/mcf to the liquefaction plant, then the equilibrium price for supplying LNG from Nigeria to the U.S. would be $3.45/mcf.

This price is barely within the perceived acceptable range. However, if we consider the situation of drilling for gas in the deepwater, the equilibrium price could be at least $4.25/mcf, which is outside the price range that is currently considered attractive.

Challenges Ahead
There are no adequate clauses either in the Joint Venture Contract Arrangement or the Production Sharing contracts that address the development of major gas projects. Most of these contracts were developed on the assumption that gas is a by-product of oil production. The Nigerian government needs to de-bottleneck its gas sector institutional structure to allow for free-market operation.

For the Nigerian government to achieve the no-gas-flaring decree by 2008, both the government and oil companies must be financially committed to the capital-intensive gas-gathering and treatment systems that need to be in place. Also, a ready market must exist to take the entire volume of gas that would be produced from all fields.

The gas price inside Nigeria is very discouraging, and for the oil companies to invest in the no-gas-flaring vision, export markets for the gas must be found that would ensure good return for investment. In addition, transparency, security and a stable political environment are necessary to increase the confidence of foreign investors.

Increasing production of associated gas may lead to an increase in oil production, a situation that is constrained by the OPEC quota for Nigeria. The only means by which Nigeria can increase gas production is to find and produce non-associated gas reserves to avoid OPEC restriction.

At the same time, floating LNG facility construction is a technology challenge in the world today, since such a project has not yet been undertaken. Other challenges include the coordination of gas produced from marginal fields operated by local contractors. Figure 5 summarizes some of the issues to be managed
in the development of natural gas projects in Nigeria.

Conclusion and Recommendation

Nigeria has adequate reserves of associated and non-associated natural gas for development. There is a strong indication that the current efforts and the planned program by the Nigerian government and the oil-producing companies will lead to an increase in gas production that will meet the demand for domestic utilisation with an excess of 2.0 tcf/annum for export in the next two decades.

Because the Nigerian government wants to stop flaring gas by 2008, there is an obvious incentive to bring this gas to the export market, likely the U.S., as LNG. This can happen as long as the producers are still willing to sell the gas for $0.30/mcf, which will give an equilibrium price of $3.45/mcf in the U.S. market. However, any additional drilling for gas purpose may give an equilibrium price of $4.25/mcf, which is unattractive by current market perceptions.