EGYPT - The E&P Offers & Exploration.

A big number of blocks have been offered since 1998 (see background in Vol. 58). To speed up the bidding process and awards, since early 2004 new blocks have been offered every three to six months by three authorities under the Petroleum Ministry: EGPC for oil E&P; Egas, created in August 2001, in charge of gas E&P and the gas sector; and Ganoub El-Wadi Petroleum Co. (Ganope), set up in 2003, in charge of all upstream and downstream developments in Upper Egypt.

To improve its offerings, EGPC has enlarged the size of blocks and extended the exploration period from seven to eight-ten years. In very important and large Mediterranean blocks for gas, the exploration period can be 12 years, as in the case of Shell's NEMDM block. The Ministry in recent years lowered signature bonuses by half. But in late 2003 it was hinting at higher bonuses and a revision of terms in the production sharing agreements (PSA), which discouraged several companies.

There are over 300 E&P agreements and farm-in arrangements involved for oil and gas exploration in Egypt, compared to less than 200 in 1995. With the help of foreign companies operating under these agreements, EGPC, Egas and Ganope have become trend-setters in offering attractive E&P terms. But some of the foreign companies have only gained good terms after having pressed their demands hard on the Egyptian decision makers.

The Petroleum Ministry has two main objectives: to maintain oil exports for as long as possible - oil imports have risen in the past two years due to a drop in production, and to optimise the search for new oil and gas reserves. The known oil fairways are mature and discoveries in newly-explored areas are small, while oil production costs in the GoS are rising. But the gas discoveries are large and production costs are to fall as the number of E&P operators rises and infrastructures are installed in new areas. The E&P strategy of the Petroleum Ministry is to bring about the biggest concentration of operators possible in all of the known fairways. As in the case of the North Sea, such concentrations reduce E&P costs and improve the attractiveness of new blocks on offer.

BP, the operator in the Gulf of Suez Petroleum Co. (GUPCO), the largest oil producer in Egypt, in May 2003 made the biggest oil discovery in 14 years during exploration around the Morgan oilfield. This is where BP had also made two important oil discoveries earlier. The well, Saqqara, contains 80m barrels of recoverable oil and BP says average annual flow rates would be 40,000-50,000 b/d. The well lies in BP's LL87 E&P concession. It penetrated the underlying Nubia Fm at the deepest oil water contact (OWC) point recorded in the GofS. This and the two earlier wells are being developed on fast track basis to help raise GUPCO's oil output (see Part 2).

The proportion of crude oil allocated annually for cost recovery has been increased by 5-15%, from 20-30% to 30-40%, depending on the location. In some cases, EGPC's operating partners are given a share of any cost oil which is not actually required to cover expenses. For blocks in the GoS, the partners' portion of profit oil has been raised to 20-30%, from 11-20%. For Western Desert blocks, the partners' share of profit oil has been raised to 17-30%, from 15-25%. In the GoS and Western Desert, the operators' share of gas has been raised to 25%, from 20%. Companies are offered the "seismic only" option in frontier areas, with no commitment to drill in the first phase if seismic results are negative. But since 2002, EGPC has been asking for all excess cost recovery to be returned to the government, contrary to a previous arrangement that split the excess between the companies and the state concern.

The Ministry of Petroleum applies a new technology for deep water exploration in the Mediterranean, with depths which could exceed 3,000 metres under the sea. For the first time, the ministry in recent years extended the offshore Mediterranean exploration zone to extra-territorial waters within what it calls "the economic zone" at distances between 180-360 km from the Egyptian shore. (It is stipulated in the 1982 UN agreement on sea rights that territorial waters stop at 20 km from the shore. Beyond that, "the economic zone" whose mineral wealth is allowed to be exploited by the countries overlooking the Mediterranean should not exceed 360 km in distance from the shore, in order to avoid trespassing half the distance separating it from neighbouring countries).

For many years, oil and gas legislation has been subject to the mining Law No. 66 of 1953, amended by Law No. 86 of 1956. Since 1972, most E&P deals signed with EGPC have been PSAs. By 1999 BP, had invested more than $9 bn in Egypt. In 1999 it concluded an agreement with EGPC which led to a conversion of its oil JV contract to a PSA. The procedure involves the following successive phases:

Exploration licences are granted to operators who win in the bidding rounds for periods of six to 12 years. These are generally divided into two or three phases. In most cases, 25 to 40% of the initial area is relinquished by the operator at the end of a period ranging from one to four years. Each contract specifies the drilling and investment obligations to be observed by the operating company. The obligations vary according to the location and importance of the permit. This procedure applies to both oil and gas exploration activities. A bonus for an oil exploration licence is paid to EGPC by the operator company, which can be up to $6m, or up to $10m, depending on the importance of the block concerned. For gas exploration the bonus is generally lower and is paid to Egas.

An oil PSA is signed between EGPC and the operator company or consortium in the event of commercial discovery. The commerciality of discovery - or discoveries - must be recognised by EGPC as being commercial. This procedure applies to both oil and gas production activities. In the PSA, EGPC always holds 50%. The oil PSA is valid for 20 years, with a possible five-year extension. The gas PSA with Egas is for 35 years, with a possible five-year extension. There are production bonuses, payable to EGPC for oil and to Egas for gas, which vary according to the levels of output. The production bonuses for gas are lower than those for oil.

When a commercial find is made, EGPC (Egas for gas) forms an operating JV and holds a 50% stake in this venture, which will be in charge of the PSA. EGPC's operating partner holding the other 50%, be that one company or a consortium, will be the real operator of the PSA area. But EGPC (Egas for gas) takes part in the technical and financial management of the operating venture, through executives nominated by EGPC (Egas for gas). The same goes for Ganope.

Each operating company must have a board of directors consisting of eight members. The chairman and three other board members are nominated by EGPC (or Egas or Ganope); and, among these, the state firm can designate one or two of the operator's managing directors. The operator designates the other four board members including the joint venture's CEO.

The cost of field development is the responsibility of the operating partner, and the investment is made prior to the formation of the operating company. Payment is calculated on the basis of 30% of onshore production and 40% of offshore production. The sharing of production comes after the deduction of development costs. The sharing is applied to 60% of oil production and 50% of gas production. The fraction not included in the PSA is used to reimburse development costs assumed by the operating partner or consortium. The production is shared according to a sliding scale based on output levels (see detailed background in Vol. 58).