NIGERIA - Exploration.

Onshore exploration and drilling in Nigeria have declined due to state funding problems in recent years. While deep-water and frontier exploration in Nigeria involves production sharing agreements (PSAs), whereby the foreign operators bear all the costs, the main onshore E&P activities are undertaken by JVs with the state's Nigerian National Petroleum Corp (NNPC). NNPC has to provide the majority of funding in line with its large equity. Funding delays by NNPC and successive budget cuts by the finance ministry have caused the foreign operators to reduce their exploration.

The offshore exploration areas, where licences have already been awarded and additional seismic data are under interpretation, are of particular importance to the Nigerian government. This is because most of the planned expansion in Nigeria's oil production capacity to 3m b/d (see OMT) will be in the deep offshore areas, which are less vulnerable to community unrest than in the case of the Niger Delta fields.

The new Nigerian President, Olusegun Obasanjo, has recently cancelled 47 offshore exploration licences. They were the subject of controversial contracts awarded to local companies in the past four years by his military predecessors. The licences were given by the military without any attempt at a competitive bidding process. They consist of: (a) 11 highly attractive blocks awarded in March 1999 to companies said to have close links to the military; (b) six blocks awarded in late 1998 and early 1999 by the military to favoured firms; and (c) 30 blocks revoked by the Petroleum Resources Department because the licencees had failed to execute agreed work programmes within the first five years of their leases.

The country's main foreign operators, led by Shell, are interested in these blocks and intend to bid for them as soon as the government puts out a tender. They include structures beneath deep and ultra-deep waters. Shell has discovered over 1.5 bn barrels of oil in deep blocks which may be related to diapirs in front of the delta slope.

In 1993/94, foreign companies had acquired 13 deep blocks. Shell took two, OPL 212 and 219 as operator. Shell also got equity in three other blocks, OPL 209, 211 and 316 - with Agip operating in OPL 316. Elf became operator in OPL 222, 223 and 309. Mobil took two blocks and got Amoco as a partner in one, OPL 221. A Statoil/BP partnership got four blocks. Other companies taking deep-water tracts included Exxon and Conoco, both having come to Nigeria for the first time. Among those farming into some of the blocks were Texaco and Total.

The PSA terms have been attractive enough for the companies to spend heavily on exploration for deep offshore oil. They are committed to invest at least $54m in each block for the initial six-year licence period, but with no fixed programme. Shell estimates each block would need $150m or more over a ten-year exploration period.

The foreign operator covers all exploration and development costs. If oil is discovered and developed, the operator simply pays tax and royalties to the government when it starts to produce. The terms are among the best in the world. In March 1999, the then military government improved the terms for deep-water licences affecting foreign companies. These included a 35% tax cut, down to 50% from 85%, and a graduated royalty plan whereby operators would pay 12% for production in depths of up to 500 metres. There is no royalty on production in waters deeper than 1,000 metres.

                    COMPARISON OF FRONTIER TERMS
              STATE TAKE (% GROSS PROJECT CASH FLOW)*

 "Marginal" Fields         "Economic" Fields         "Upside" Fields
Country     State Take   Country     State Take   Country     State Take
Nigeria        47.5%     Nigeria        54.4%     Nigeria        55.7%
Canada         51.3%     Canada         62.8%     Canada         66.7%
Angola         65.8%     Angola         67.4%     Angola         66.9%
Gabon          70.7%     Gabon          67.5%     Gabon          69.1%
Indonesia      73.5%     Indonesia      70.9%     Indonesia      70.8%
Malaysia       76.3%     Malaysia       73.0%     Malaysia       74.4%

*"Gross project cash flow" equals gross revenue, less gross costs only.












Source: Petroconsultants, Feb. 1995

Deep-water drilling is very expensive, as the blocks are at least 1,000 metres below sea-level and the oil probably lies another 2,000-4,000 metres deep underground. A 3D seismic work, a rig and a first well would cost $50m, and the drilling of a second well would cost another $30m. Up to $1 bn would be required to bring a production platform online.

For Nigeria's deep-water blocks to be developed on the scale wished by the government, a total investment of more than $10 bn could be required. Operators would need to find fields able to produce at least 300,000 b/d to justify investment on such a scale.

Most of the seismic testing on the blocks that were taken in 1993/94, with the Benin embayment being most popular, was completed in 1995 and drilling on some tracts began in the second half of that year. In March 1996, Shell found a rich oil reservoir in its Bonga-1 well in block OPL 212 at a water depth of more than 1,000 metres and 2,000-3,000 metres under the seabed. Then this was the most successful exploration effort in Nigeria's deep-water prospects. (OPL 212 is held 55% by Shell, 20% by Exxon, and 12.5% each by Elf and Agip). Shell later found another rich oil reservoir in Ngolo-1 well in its second block, OPL 219. Each of the two wells cost about $30m to drill. Shell was to drill other wells and develop the fields for production to begin in 2000.

Statoil/BP found 100m barrels of oil in a trailblazing Oyo-1 well in late 1995. Work was suspended as the field was too small to justify delineation at that stage, due to high costs. The well cost almost $15m. Two other wells drilled in 1996 were not encouraging. Mobil/Amoco found some oil in OPL 221 but the first well, which cost about $20m and was drilled to a total depth of almost 9,000 metres, was plugged and abandoned. Agip, Shell's operating partner in OPL 316, found some oil there but drilling was suspended. Instead, Agip concentrated on 3D seismic work.

Elf drilled two wells in OPL 309 which were not encouraging. Further drilling took place in 1998, as Elf still believed the prospects in its three blocks were good.(Off Angola, Elf in August 1997 announced the discovery of Dalia field at a water depth of 1,360 metres, with more than 1 bn barrels of oil reserves and the potential to produce over 200,000 b/d by 2000/01. This is 3km from the Girassol field which Elf discovered in 1996 with about 700m barrels of reserves and also with a potential to produce 200,000 b/d by 2000/01. The fields lie in Elf's Angolan block 17, which it says could eventually have 5 bn barrels of proven oil reserves and would make it the most prolific block in West Africa. Elf's other major oil discoveries in West Africa include Nkossa and Moho, off Congo).

The offshore potential has been the subject of territorial dispute between Nigeria and Equatorial Guinea. There are conflicting claims over the offshore Zafiro oilfield located near Equatorial Guinea's Bioko Island, in the Gulf of Guinea. Mobil started oil production at the field in September 1996 under a contract with Equatorial Guinea. However, Nigeria has granted production rights there to Elf.

Nigeria also has a territorial dispute with Cameroon over the oil-rich, 600- square mile Bakassi Peninsula which separates the two countries. After

heightened border tensions led to a number of clashes between the two states in early 1996, the UN sent a mediation team to the region. The International Court of Justice in the Hague has since reviewed the case. Nigeria claims that an 1858 treaty places the Peninsula in its territory. Cameroon contends that Nigeria offered it the region after Cameroon refused to help Biafran rebels during Nigeria's 1967 civil war.