HOW NIGERIA LOOKED AT FISCAL TERMS, PROSPECTS

M.A. Ofurhie, M.C. Amaechi, A.O. Idowu
Nigerian National Petroleum Corp.
Lagos

The allocation of funds among investment possibilities must of necessity include evaluation and ranking of alternatives.

An essential prerequisite is a geophysical/geological evaluation followed by a reservoir/production analysis resulting in the prediction of recoverable reserves, reservoir performance, optimum method of development, and initial offtake return.

An economic model of a typical Niger delta medium cost field with reserves of about 100 million bbl of oil under the royalty/tax system reveals that it is difficult to develop such a field when located offshore.

This paper examines case histories involving smaller and larger field developments.

The authors observe that high and low levels of exploration and production activity during 1967-87 in Nigeria correlate with high and low pricing periods, respectively.

The Nigerian federal government's profit incentives given to operating companies in 1977, 1979, and 1985 tend to gear up exploration and production activities in these years.

INTRODUCTION

An insight is given on the economics of oil and gas exploration and development in Nigeria involving the economic viability of an average or medium cost oil field with reserves of about 100 million bbl and the financial implications for field development under the petroleum profit tax/royalty system.

A review of the federal government's fiscal regimes is also given with respect to their trends and impacts on exploration and development in the Nigerian oil industry.

Oil is the single most important commodity and the prime mover of the Nigerian economy, contributing more than 85% of national revenue and 90% of foreign exchange earnings.

Oil production and export started in 1958 at a production rate of 5,100 b/d of oil. The volume doubled the following year. Crude oil production rose to 2 million b/d in 1973 and reached a peak of 2.3 million b/d in 1979.

Nigeria's current production quota as a member of the Organization of Petroleum Exporting Countries is about 1.8 million b/d.

MEDIUM COST OIL FIELD

An economic evaluation of a typical medium cost oil field with about 100 million st-tk bbl of oil in place under the Nigerian fiscal system has been determined by employing the discounted cash flow technique.

The input parameters into this model are shown (Table 1).

Depletion drive was chosen for a conservative base case, being one of the least efficient drilling mechanisms, and it is assumed that there is no direct evidence for the more effective drive mechanism such as water and gas cap drive.

Hence the reservoir pressure would decline rapidly while the gas-oil ratio, showed as low initially, rises to maximum and drops. Water production is negligible, and a recovery factor of 26% is selected with gas injection.

The reserves for this model are about 26 million bbl, and the simulated production profile gives the initial well potential as 2,000 b/d of oil.

The plateau production rate is 9,000 b/d by employing five wells as producers and two as gas injectors.

The forecast of the annual amounts of money absorbed or generated illustrates the relation between revenues, technical costs, host government take, and the cash flow of a venture of which the major input parameters are shown (Fig. 1).

The cash flow would result from development of a 26 million bbl field. Dominant cost item during the early years of the venture is the capital expenditure of $100 million required to build the platform, production facilities and pipeline, and drill and complete the wells.

The remaining technical costs representing the operating costs, concern expenses for maintenance, lifting, treatment, transportation, insurance, and overhead.

These costs are the dominant item during the last years of the venture and the eventual cause for abandoning the field.

The largest cost item in this model is the host government take, consisting of royalty and taxes. The relative magnitude of the various cash flow items can be judged from a cumulative cash flow (Fig. 2).

Interpretation of profitability indicators from this cumulative cash flow reveals that a minimum investment of $70 million (the depth of the cash sink or maximum exposure) will be retrieved in total in 6.3 years payout time (Figs. 2, 3). The project will have gained a cash surplus of $83 million at the field's abandonment after 18 years (Figs. 4, 5).

The most important profitability indicators are the result of discounting the cash flow (Fig. 6).

This implies that the cash flow elements of later years are reduced by a discount factor that reflects the value of money to the investor taking into account alternative investment opportunities and business risk.

For this model, the present value cash surplus/deficit (PVCS) of the cash flow is plotted against the discount rate equals the ultimate cash surplus (undiscounted), but 8% and 12% PVCS would apply to low and medium risk projects while 15% could apply to projects with risks that are considered normal in the oil and gas industry.

The discount rate for which the present value equals zero is the earning power (rate of return).

In view of this uncertainty, the economic result thus obtained for this model is the base case and should be regarded with some reservation, though it is the most probable outcome of the venture within limits of the input parameters.

In order to appreciate the effect of possible variations on this base case, an alternative oil price scenario is defined, evaluated, and analyzed to reveal the vulnerability of the model to fluctuation in oil prices.

In using oil price as a sensitivity to estimate possible variations on the base case, the authors have given the cumulative cash flow graph corresponding to the breakdown of the revenues of a medium cost oil field in Fig. 1 under the assumption that the oil price will not be constant at $30/bbl but will stabilize at $15/bbl (Figs. 4, 5, and 6).

The net result is that the payout time increased to 8 years, total revenues dropped by more than 50%, and both government take and cash surplus were much reduced.

Equally, the economic life of the project has been reduced 5 years, lowering the reserves produced. It can thus be inferred that the development of a medium cost oil field is difficult and sensitive to fluctuations in oil prices, particularly when located offshore.

CASE HISTORY 1

The oil field for this case history is offshore in the Niger delta.

It contains three structural leads, A, B, and C, which were initially identified from mapping of this area based on a total of 1,800 line km of 2D seismic data, with some geologic and exploratory drilling activities conducted between 1980-83.

The A lead eventually became A field, spudded in 1981, and registered as an oil and gas discovery. This A field is 44 km offshore from the nearest onshore terminal in 65 m of water. Development of A field involved full processing offshore, drilling with tender rig, and gas reinjection.

Ultimate recovery was estimated at 69 million bbl with a projected 13 year economic life, employing 16 producing wells and one gas injector.

The C lead became the C prospect, which was found dry.

The B lead resulted in the B prospect (Fig. 7). Well B-1 was drilled on the northern part of the structure in 1982, while the B-2 appraisal well was located in the southern part.

B-1 discovered oil on water in a sandstone interval at 3,087-3,103 m, while B-2 found gas on water at 2,76292 m.

The two wells were drilled to total depths of 3,350 m and 3,040 m subsea, respectively, before running into the top of overpressure zone as interpreted on the seismic sections and well logs.

Field development feasibility of B field based reserves estimation for the field on three different options, involving the upper, medium, and lower limits of estimated reserves.

The upper limit (Case 1) assumes that the entire area and respective volume of the A structure above the oil-water contact at -3,103 m is oil bearing inspect of possible interference of some secondary faults (Fig. 7).

Using the reservoir parameters of the nearest prospect, A, i.e. porosity 0, water saturation (Sw), formation volume factor, and ultimate recovery of 24.80%, 19.6%, and 2.30, and 30% respectively, the estimated recoverable reserves for the upper limit were 9.6 million bbl.

The medium estimable model (Case 2) is similar to Case 1 but with the presence of a gas cap from -3,087 m subsea, which corresponds to the top of the oil zone in B1 well, i.e. up to -3,035 m subsea, near the crestal zone of the structure. The estimated recoverable reserves would be 4.5 million bbl with the same set of reservoir parameters extrapolated from A field (Fig. 8).

For Case 3, a minimum production area just around B-1 well was considered, thus assuming that the oil zone does not extend beyond the fault that is present to the south of B-1. The estimated reserves would be 1.21 million bbl (Fig. 9).

From the various options established for estimation of reserves in B field, the upper (most optimistic) limit estimate is 9.61 million bbl of recoverable oil, while the lower (most conservative) limit is 1.21 million bbl of recoverable oil.

Even if the upper case of 9.61 million bbl is precise, installation costs of production facilities and operating expense in 70 m of water may not guarantee a profitable rate of return on investment in field development. The field development may later become attractive when and if bigger oil reserves are matured in this locality, which may be hooked into a gathering system for a profitable development.

CASE HISTORY 2

This field is offshore in the Niger delta in 60 ft of water some 4.7 miles southwest of a production platform/ gathering system.

A 16 in. pipeline was laid to this platform for crude oil evaluation from the new field.

The basic data initially scored and assumed for the development scheme include:

Royalty 18.5%
Seismic data availability 10%
Tangible drilling 25% (20-30% is considered good.)
Investment tax credit 10% (5% for onshore field)
Projected life span for field production 26 years

Geologically, the two reservoirs are Structurally and stratigraphically controlled in an east-west alignment (Figs. 10, 11) within a major boundary fault to the north and another boundary fault on the southern end.

The field consists of multiple reservoirs and is being developed in two phases.

The deeper reservoir is at -6,329 ft subsea, with the gas-oil contact at -6,396 ft subsea and an oil-water contact at -6,578 ft subsea (Fig. 10).

The shallow reservoir calls for an entirely new concept to be further tested before development. This reservoir (Fig. 11) was discovered at -5,123 ft subsea and is composed of about 2,000 ft thickness of stratigraphic units requiring finer resolution, being tackled by reprocessing of some 3D seismic data.

The proved plus probable reserves obtained for the new field compared with the nearest production platform (about 4.7 miles to the northeast) are shown (Table 2).

The following profitability indicators were determined and considered favorable and economically viable for the development of this field:

Rate of return 51%
Profit investment ratio obtained by net cash after tax divided by total investment of $3.03
Present value ratio $1.83 at 10% discount rate
Maximum cash in red $34 million in 1992
Payout period 4.6 years in 1994
The net present values for $540.76 million are $197 million at a 10% discount rate, $128 million at 15%, and $85.3 million at 20%.

An ultimate recovery of 857.7 million bbl of 38 gravity oil will be produced during 26 years, with a maximum cash in red estimated as $34 million, while the total cash recoverable will be $85.3 million at 20% discount rate, yielding a 51% rate of return.

EFFECTS ON NIGERIA

Here is a summary of the effects of crude oil prices and fiscal regimes on exploration/development in Nigeria.

Since Feb. 1, 1983, national fiscal technical cost and national margin are fixed at $2/bbl (Table 3).

The posted or tax reference price and official selling price of 26 Nigerian medium crude blend in Nigeria during 1976 to 1985 were compared.

During periods of lower or depressed oil prices (i.e. 1976-79 and 1983-85), the posted or tax reference prices are about 6% higher than official selling prices, while for higher oil prices (e.g. 1980-82), the OSP is about 10% higher.

Both posted and official selling price curves trend in similar fashion, correlating with global oil price trends.

A review of joint ventures' seismic activity reveals that seismic acquisition coverage more than doubled in 1976-79, from 9,467 km to 22,764 km but fell from 1979-83 by about 90%, after which there was an upturn from 1985.

Similarly, exploration/appraisal footage drilled appreciated by 75% in 1976-80, after which it decreased progressively to 1985 by 71%.

Drilling began to pick up from 1986 but remained below the pre-1980 activity level.

The production level, exports, and revenue derived from crude oil proceeds more than doubled in 1970-79. This trend was reversed in 1979 and 1987 in that production fell from 2.34 million b/d to 1.32 million b/d, a 42% drop.

Correspondingly in the same period, revenue derived from crude oil exports decreased sharply. All factors contributing to present fall in oil production virtually have their origin in global rather than purely domestic conditions.

The Nigerian government offered the first major package of fiscal incentives in 1977 calculated to stimulate exploration investments in new areas with a view to increasing oil reserves to support the high level of oil production.

The package of incentives designed to attract new companies' interest in new acreage, particularly the offshore blocks, are:

Exploration incentives
Modification of profit tax
Modification in royalty rates
Enhanced annual allowance, and
Investment tax credit.

The introduction of the 1977 fiscal incentives marked a systematic attempt to establish appropriate climate for increased exploration in Nigeria.

Later the government established appropriate technical costs designed to account for rising costs of exploration equipment as costs of borrowing money so as to determine adequate profit margins that would induce oil companies to undertake necessary investments.

Another major fiscal review was undertaken in 1979 and resulted in the signing of 11 service contract agreements for land and offshore exploration.

There was decline in exploration after 1979, followed by an upturn again identified in 1985 due to another profit incentive through the memorandum of understanding agreement for enhancing crude oil exports and encouraging investments in exploration and development.

This agreement was signed between the companies and federal government Jan. 1, 1986, and a mechanism was introduced through the memorandum that ensured that producers realized the guaranteed margin on their equity share of crude production using actual market price,

Producers in return committed to investment programs and guaranteed lifting of some negotiated volumes to NNPC's share of crude production. This has worked well since 1986.

The memorandum was responsible for the high intensity of investments in Nigeria while they are reduced in many other exploration and producing areas of the world.

FUTURE CHALLENGES

In light of recent experience, oil and gas exploration in Nigeria appears to have three main challenges, namely:

How to develop more efficient techniques for finding the oil and gas fields that may so far have eluded all previous techniques.
How to convince the authorities to release funds for oil and gas exploration.
How to prevent qualified and experienced oil and gas explorationists from decamping to more stable sectors of the economy.

The frontier areas of exploration in the 1990s will be the deep offshore blocks and the inland basins, where Nigerian National Petroleum Corp. has already pioneered through its direct activities.

Looking at the existing acreages in mature exploration areas, the biggest fields would have been found, and new discoveries tend to be smaller and therefore less attractive.

Incentives that would ensure a high level of oil industry investor confidence are necessary in order to increase exploration and discovery of new reserves, as well as assure timely development of reserves found.

The memorandum of understanding was a good start in this respect. The main national objective is to raise the oil reserves base to 20 billion bbl by 2000.

COMMENTS, CONCLUSIONS

The development of a medium cost oil field with reserves of about 100 million bbl is rather difficult and renders the venture unattractive to investors, particularly when located in a more difficult offshore environment.

A venture of this magnitude is rather sensitive to fluctuations in oil price and constitutes disincentive to exploration and development in frontier areas.

The host government's take (royalty plus tax) constitutes the largest cash out item, and when coupled with high technical cost of production would result in erosion of profit margin.

High oil price seasons tend to tally with peak exploration development and production activity levels, as seen in Nigeria from the mid-1970s until the present, namely 1977, 1979, 1980, and 1981.

During low oil price periods such as 1982-83, operations in terms of exploration and field development are low keyed. Oil price increases made oil exploration and development attractive, while low oil prices acted as disincentive.

It is recommended that Nigeria should retain its membership in OPEC for the benefit of oil price stabilization through production quota and achievement of fair share of the oil market.

Contract options should be encouraged to take care of the peculiarities of remote and virgin areas, including deep waters far away from existing crude evacuation facilities.

Increased exploration and development must be sustained in spite of the oil glut through regular review of the fiscal system with exploration investment incentives for creating the appropriate climate.

Government's legislative policies should be very responsive to changes in the industry and aimed at not only government's maximization of its proceeds from the industry but also at protecting the industry and encouraging its growth.