The recently introduced amendments to two existing oil agreements between British Petroleum (BP) and the Egyptian General Petroleum Corporation (EGPC) have opened the door to much debate on the quality of negotiations and the terms involved. Although the amendments have already been approved by the People's Assembly, they still await the president's signature in order to pass into law. Hussein Abdallah and Amr Kamal Hammouda argue that the terms of the amendments are not in Egypt's favour In June this year, the People's Assembly approved the amendment of two agreements Egypt signed with British Petroleum (BP) for deepwater oil and gas exploration and production off the coast of Alexandria. The agreements were originally concluded in 1992 and 1999. The amendment now only requires the president's signature in order to pass into law. The first part of the amendment seems positive on the surface. It provides that the contractor (BP), after it begins to develop the gas fields it discovers, will pay the Egyptian General Petroleum Corporation (EGPC) between $3-4.1 for every million British thermal units (Btu, which is equivalent to 1,000 cubic feet) of gas. What is not mentioned is that the contractor is only obliged to meet the needs of domestic consumption at the stated price within the bounds of its quota of the total production. The surplus is retained by the contractor to be liquefied and exported for its own profit. It follows that the delivery and receipt to and from EGPC is a purely formal process because gas is not stored in tanks, but rather flows non-stop through the pipelines from its source to its destination. Because of this there has to be an agreement in advance between the EGPC and the contractor stating the volume and times of gas deliveries. Accordingly, the amendment stipulates that the contractor must prepare an annual production schedule in accordance with the gas and condensates delivery contract, which, in turn, confirms that the delivery and receipt process occurs on paper only. This brief introduction leads us to a more extensive discussion of the potential dangers and risks of the process, which could jeopardise the Egyptian petroleum sector and threaten its independence in managing our country's most important source of natural wealth. The original agreements were based on the production sharing model that prevails in Egypt. One of its terms was that the foreign partner pays all the expenses for the exploration processes. If the partner is unable to discover a commercially viable field, he has to leave without recovering his expenses. If, on the other hand, he does make a commercially viable discovery within the stipulated period, the contract would remain valid for about 35 years and the foreign partner would recover his expenses from a certain percentage of the total production (the customary rate is 40 per cent), as calculated in dollars at the current rates of oil or gas exports. The contractor would continue to obtain this rate until he recuperated the full value of his investment. Additionally, the contractor is also entitled to a profit payment (generally set at 15 per cent of the total production). The host state (Egypt) keeps the rest. Thus, until he recuperates his initial investment the contractor obtains around 55 per cent of the total production and the host state around 45 per cent. It has been the custom of the Egyptian petroleum sector to pay the government fees and income taxes for the contractor. The bill to amend the contracts states that the contractor has fulfilled his commitment on the exploration processes by having laid out some $800 million and that the "primary reserves" that are now available to him amount to five trillion cubic feet of gas and around 55 million barrels of condensate. The gas in excess of this amount, which is referred to as "supplementary reserves", is not mentioned in the amendment. However, the contractor can develop and produce from both reserves, which would require an investment of $9 billion, according to the contractor's estimate, from January 2006 until the end of the development and production period which conventionally last 20 years with two optional 15-year long extensions. In exchange for his outlays over the next 35 years (the remaining duration of the contract after amendment) the contractor is now unilaterally entitled to the yield of the primary reserves and to 61 per cent of the supplementary reserves, as opposed to 39 per cent for the EGPC. The ratio is almost exactly the inverse of that which existed under the agreements before they were amended. The supplementary reserves that the contractor destines for export are also subject to the same bookkeeping method of delivery and receipt described above. As for condensates and any crude oil that is discovered (the amounts of which are likely to be very small), these are to be split equally between the contractor and the EGPC under the amended agreement. Obviously, EGPC will purchase the contractor's share of these substances for domestic consumption at the rate of at least $140 per barrel for condensates and at the market rate for crude oil. What were the justifications for introducing these amendments into the agreement? Which of the parties of the agreement asked for the amendment? The contractor must have insisted upon the amendment and pressed his demand by means of the threat to stop developing the fields it discovered in 2000. Caving in to the contractor's demands has far- reaching ramifications. Not only did it undermine the principle of production sharing prevailing since 1960, it encourages all other foreign firms operating in Egypt to ask for similar amendments. It would, therefore, have been wiser to apply the principle of sole risk which allows the state party to take over the development of the fields when the contracting party defers the development for five years. . If necessary, the government could resort to foreign expertise engaged on the basis of service contracts and it could take out a loan for the development using a portion of the production as collateral. As mentioned above, the amended contract gives the contractor sole control over the entire yield of the primary reserve and his share of the supplementary reserves. Yet, the nine billion estimate that the contractor made covers quite a long timeframe. If it is difficult to project development and production expense five years ahead, it is virtually impossible to make a projection 35 years into the future. Therefore, the contractor has probably inflated his projection in order to justify a revision of the terms of the contract. Under the original agreements, there was a clear link between expenditures and the contractor's share of production for recuperating costs and making profit. This link vanishes under the modified agreement. As a result, not only are the contractor's development and production projections unascertainable, but the contractor is not actually obliged to spend $9 billion. In other words, the revised agreement makes an explicit contractual obligation to the contractor, granting him the full yield of the primary reserves and 61 per cent of the supplementary reserves, regardless of how much he spends over the contractual period. Thus, instead of recovering his expenses in instalments and splitting the surplus with the EGPC, the contractor will now have the opportunity to accelerate the recuperation of his investments and his reaping of the profits as soon as the revised contract goes into effect. This deficiency could have been offset by mention of a specific figure for the internal rate of return. However, the amendment bill made no mention of such a rate, contrary to the claim of the Petroleum Ministry that the contractor's return would not exceed nine per cent while the figure in Libya and Iraq was as high as 25 per cent. In Egypt, under the revised agreement, in exchange for the $800 million it has invested in exploration and for the $9 billion it says it will spend during the contractual period, available figures suggest that BP will reap more than $20 billion from its domestic and foreign sales from the production of both the primary and supplementary reserves. This estimate, is based on the price cited in the revised agreement ($4.1 per Btu), whereas the price is actually expected to skyrocket during the contract period. The revised agreement places no restrictions on where the contractor can market his share of the production. His decision over whether to sell locally or abroad will rest solely on the criterion on which is more profitable. This can have serious ramifications; the EGPC estimates that Egypt total gas reserves are about 78 trillion square feet of gas. Assuming this figure is correct; the entire reserve will not be put into production immediately. Rather, only 35 trillion cubic feet can be tapped, yielding an annual production of 55 million tonnes of equivalent oil (toe), according to Wood Mackenzie. Taking this figure together with the EGPC's prediction of an annual five per cent increase in production, the reserves should yield 64 million toe by 2015. Add to this the production from the primary reserves (five trillion cubic feet) that will rise by the same rate to nine million toe, the total production by 2015 will come to 73 million toe. Now, the natural gas deficit in the domestic market has averaged around 10 million toe. If BP is expected to contribute no more than 12 per cent of this deficit, which accounts for 1.2 million toe, it would, therefore, be left with some 7.8 million toe to market abroad without any control on the part of the Egyptian government. There was also no justification for increasing the price the EGPC should pay for its gas purchases from the contractor. Given that the original agreement was ratified on the basis of the host country's right to obtain its gas needs for domestic consumption at a cost of no more than $2.65 per million Btu, even the minimum rate of $3 per million Btu cited in the new agreement is higher than the maximum price under the old terms. One could also argue that crude oil purchase for domestic purposes is also overpriced. Under the revised agreement Egypt is expected to pay the going international market rate for any oil it buys from the contractor's share. Yet it has always been the custom for the contractor to offer the host country a discount on that rate. That discount might even be as low as cost price. Condensates present another pricing curiosity. These have only one use, which is to be added to crude oil to reduce its viscosity and improve its quality. As the EGPC is the only customer for this product, the contractor cleverly priced it at $140 per barrel. As a barrel contains about six million Btu, the price per million Btu of condensate comes to $23. The $140 price tag is all the more odd in that the best crude oil these days sells at between $70-80 per barrel. Under the revised agreement pricing and other terms can be renegotiated every five years. But this comes with a number of caveats, the most important being grounds for "essential changes" which, in all events, cannot exceed 15 per cent over previous pricing levels. It follows that the profits from any increases in export prices during five-year period preceding a renegotiation phase are pocketed by the contractor, on top of his earnings from the primary reserves (to which he is entitled in exchange for his investment costs). This provision demolishes the production sharing cornerstone of the original agreements, whereby the EGPC obtained more than 60 per cent of the production, even if it undertook payment of the royalty fees and income taxes on behalf of the contractor. The revised agreement, like the original one, contains a provision to the effect that if existing laws and legislation pertaining to the petroleum sector change in a manner that is significantly detrimental to the contractor, the parties shall negotiate with an eye to restoring the economic equilibrium that existed between them at the time the amended agreement went into effect. Yet, the new agreement contains no similar provision for the state party. Apart from the abovementioned opportunity, with its attendant restrictions, to renegotiate pricing and other terms every five years, the host country cannot ask for a redress of the economic balances. More significantly, what justification was there for raising the price of the gas the EGPC purchases from the contractor under the new terms when there has been no significant change in the Egyptian laws and regulations pertaining to the petroleum sector? Notably, in January 2008, the People's Assembly committee that was formed to respond to the prime minister on this matter advised levelling an extraordinary tax on profits that are reaped by petroleum firms operating in Egypt as a result from unexpected hikes in petroleum prices. Such a measure was adopted by Algeria, for example, which succeeded in garnering a portion of the extraordinary profits during the recent spikes in international oil prices. However, the Egyptian petroleum sector has yet to heed this advice. Under the revised agreement, the general director and assistant general director of the contracting party are responsible for overseeing development and production. It also calls for the creation of an eight- member joint development committee in which each party is represented by four members. Yet, the powers of this committee are largely advisory. By contrast, the original agreements handed development and production operations to a joint venture company that was headed by an Egyptian. The Gulf of Suez Petroleum Company (GUPCO), owned in equal shares by BP and EGPC, is an example. This formula served as a check on the contractor's natural inclination to accelerate the recovery of his investments and the reaping of profits. Beyond the foregoing problems, there are many points in the revised version of the agreements that require clarification. Those pertaining to the development, production and marketing of the supplementary reserves are an example. There is no mention of volume or of the timeframes for development and production of these reserves. Will these processes begin at the same time as the development and production of the primary reserves, or will they be deferred until the primary reserves are depleted? Such important questions are left unanswered. In addition, the revised version of the agreement defines the gas and condensate delivery contract merely as "a written contract between the EGPC and the contractor signed in accordance with this amended agreement and which contains the terms and conditions pertaining to the handling of the gas and condensate and their delivery by the contractor to the EGPC. In other words, the contract will only be drawn up after the revised terms and conditions are ratified. The production sharing contracts that were introduced in Egypt in the 1960s were a step ahead of the conventional exploration and drilling concessions that had prevailed in the Gulf since 1950s. The bill on the revised terms for the North Alexandria deepwater oil and gas production threatens to turn the clock back to the concession-royalty system. Moreover, with a royalty of 10 per cent, the reduction of the income tax rate from 40 to 20 per cent and the exorbitant prices the government will have to pay for the quantities of the contractor's share in production in order to meet the needs of domestic consumption, the terms are even less attractive than they were 60 years ago. Hussein Abdallah is a petroleum and energy consultant.
