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Egypt gas agreements: from production sharing to tax/royalty

All oil exploration and production concession agreements in Egypt have been operating according to Production Sharing Agreements since 1973. This was a shift from the tax/royalty system towards equal sharing agreements concluded between the government, represented by the Egyptian General Petroleum Corporation (EGPC), and foreign companies, with a view to reduce the pressure on the …

All oil exploration and production concession agreements in Egypt have been operating according to Production Sharing Agreements since 1973. This was a shift from the tax/royalty system towards equal sharing agreements concluded between the government, represented by the Egyptian General Petroleum Corporation (EGPC), and foreign companies, with a view to reduce the pressure on the state budget. The sharing system was also prevalent in developing countries with respect to prospecting and producing crude oil, and was then known as the Indonesian model.

With the beginning of gas exploration activities in Egypt in the mid-1980s, the production sharing agreements were modified to accommodate the gas industry. Prior to this change, partners were not permitted to share gas unless it was exported as liquefied natural gas (LNG). The amendment was made to generally include gas in such agreements using a special formula for pricing. It could be said that it was acceptable to use this system for gas in shallow water and superficial layers.

However, with the prospecting and production of most of this superficial gas, Egypt entered a new era of deepwater gas, produced under high pressure and high temperatures. Applying Production Sharing Agreements to deepwater gas has clearly proved the least optimal system for the future and the government was compelled to consider other systems, such as tax/royalty agreements, to avoid the drawbacks of production sharing and reduce the risks of investing in this new sophisticated gas business.

Why are Production Sharing Agreements a cause for concern in deep water gas, and what does the tax/royalty system offer instead?

Cost recovery

According to Production Sharing Agreements, part of the production is allocated for cost recovery. Since extraction of deepwater gas under high pressure and high temperatures is capital intensive, accounting for billions of dollars, it is expected that the cost recovery share would be high in the early years of production, reaching 70-80%, in order for the foreign investor to generate an acceptable rate of return. In Egypt, traditionally, the foreign investor’s share in cost recovery has never exceeded 40%. As such, after adding the profit share, the foreign partner cannot be said to be receive a share of production higher than the government. This also ensured the approval of the agreement by parliament, smoothly and without objection.

Moreover, most foreign investors face difficulties with the EGPC and the Egyptian Natural Gas Holding Company (EGAS) in terms of procedures for cost recovery approvals, and usually end up failing to recover the full amount. Thus, upon entering such agreements, the foreign partner already estimates that 10-15% of the amounts disbursedwill not be recovered.  As such, this unrecovered percentage is factored in the calculation of the gas price.

As discussed, it is clear that foreign investors are forced to develop any discovery with specific investment costs that enable recovery of investment, regardless the size of the discovery or market needs. This is what is known as “riding the cost recovery line”. Nevertheless, if any discovery is developed using the tax/royalty system, the foreign investor will be the owner of the full production (but cannot export it without government approval, and will be able to sell only in the local market). Accordingly, the investor is freed from any cost recovery constraints, which will reflect on the volume of gas produced. Thereby, the gas price will realistically reflect the discovery size and cost of production.

Gas pricing

The foreign partner’s share in cost recovery or profit with regards to gas discovered and produced through Production Sharing Agreements is fixed by the concession agreement, which is approved by parliament and cannot be changed. The gas price is agreed ahead of production, and before any investment, according to the discovery input and market conditions at that time, which naturally change over time. Usually, such agreements are not suitable for any future investment without renegotiating the gas price to reflect the economic situation at the time of the new agreement. Given that gas pricing renegotiations are usually complicated and lengthy, such negotiations delay economic growth nationwide.

Conversely, if the foreign investor operates under the tax/royalty system, the market volatility and the discovery input will have an impact on the foreign investor’s profitability, and thus on the amount of taxes on profits payable—which will ultimately accommodate this shift. If the changes are positive, the investor’s profitability will rise, increasing the payable taxes in the process. However, if the market changes are negative, profits and taxes will plummet. This flexibility will, therefore, allow the investor to work uninterrupted under all circumstances, and without requesting a renegotiation of the gas prices.

Nagy Iskander
Nagy Iskander

Gas subsidy

According to Production Sharing Agreements, foreign investors receive a share of production in two divisions; one for cost recovery and another for profit reward. Both shares are sold to EGAS based on the negotiated price. EGAS receives the remaining production. Based on this, the cost of gas for the government is the average of the amounts paid to the foreign investor for the share of production and the remaining production received free of charge by the government (regardless of the taxes and royalty paid by EGAS on behalf of the investor to the Ministry of Finance, since both are government agencies).

This is what is called the weighted average cost of gas. The weighted average cost of gas for the government varies according to changes in the amounts of cost recovery in time. Thus, it is difficult to identify the real cost borne by the government and, accordingly, the subsidy required to cover the difference between the real cost of gas and the gas price for end consumers.

In contrast, if the foreign investor operates under the tax/royalty system, the investor would sell all production to EGAS, either at a fixed price or a fixed formula, which makes it easier for EGAS to add a margin to cover the overheads. This is also reflected as the real market price. As such, if the government prefers to sell gas to the power sector for a lower price, the subsidy will be known and easily calculated. Moreover, this tax/royalty system will help resolve the conflict between the Ministry of Petroleum and the Ministry of Finance concerning subsidy accounts and taxes payable by EGPC/EGAS on behalf of the foreign investor. The tax/royalty system is simpler as it results in the investor paying all taxes directly to the tax administration.

Gas market deregulation

The ministry and EGAS recently announced that they are working on a plan for “gas deregulation”.  According to this plan, the foreign investor would be able to sell gas directly to the domestic market. Nevertheless, if the investor is operating under a production sharing system, the investor’s share will change over time due to the fluctuations in the cost recovery share, which is mainly dependent on the gas price.

Meanwhile, any gas sales agreement between producer and consumer stipulates that the gas volumes are fixed for a long time, whereas this prerequisite would be difficult to fulfil if the investor is operating under the production sharing system. However, if gas is produced under a tax/royalty system, the gas entitlement will be fixed and known in advance. This in turn facilitates the conclusion of the gas sale agreement between producer and consumer.

Decommissioning costs

These are the expenses incurred in restoring the location of the gas exploration or production to its original state, to preserve the environment. By the end of the production from any concession, all installations and pipelines used in production shall be removed to restore the environment to its original state.

Typically these costs are very high in large-scale offshore platforms and onshore facilities. If reserves are produced under the production sharing system, all rights to the assets and facilities used in production will revert to the state after the costs are fully recovered by the foreign investor. Thus, all decommissioning expenses will rest with the state. Also, it is common practice under this system for the foreign investor to relinquish the agreement in the later stages of production due to economic unfeasibility. States, though, still need this production, even if minimal, leading the state to undertake the production process, and in turn become responsible for all decommissioning expenses.

Although EGAS recently introduced clauses to the newly approved concessions providing that the foreign investor pays for decommissioning, the application of said clauses is not guaranteed because such costs depend on the level of production and prices in the years prior to decommissioning. Moreover, this would be subject to negotiation at the time of decommissioning.

Should the foreign investor operate under the tax/royalty system, production—to the last drop—and decommissioning will remain the responsibility of the investor, as all the facilities would be owned solely by the investor.

Volume of new E&P companies willing to enter the Egyptian market

Many of the E&P companies would like to begin operations in Egypt. However, these companies view operating under the production sharing system as an increase the investment risk to a prohibitive extent, with all the challenges facing cost recovery, in addition to the delay in payment. Thus, the already existing E&P companies with experience dealing with EGPC/EGAS will continue to be the sole players in the market, which limits competition over any new tenders.

Nevertheless, if the tax/royalty system is introduced, many large- and mid-sized E&P companies will work hard to penetrate the Egyptian market, given their knowledge and experience with this system worldwide. This will result in more competition in the Egyptian market, and will reduce investment risks, which could be balanced against projected revenues.

Joint ventures

As for any commercial discovery of gas or oil, according to all concessions operating in Egypt, issued as laws by parliament, it is obligatory to form a joint venture between EGPC/EGAS and the foreign investor to develop and produce all the reserves discovered. Despite the fact that, according to the bylaws of these joint ventures, both parties have the right to dual signature regarding almost all significant decisions within the company, traditionally, the Egyptian side is always in control of all administrative structures and financial decisions.

This is justified by the fact that any amounts spent by the foreign investor will be recovered from the cost recovery pool, which renders this money as public funds, and hence subject to all controls governing disbursement. This leads to a very complicated decision-making process within the company, and is frustrating to the foreign investor, who feels unable to conform to the administration or to control the increase in the headcount of the company. Also, the foreign investor always faces the threat of the non-approval of cost recovery.

However, if production is governed by the tax/royalty system, establishing joint ventures will be redundant and the foreign investor can undertake production through an organisational structure established in Egypt. Usually, such organisations are staffed with well-trained Egyptians, which will have a positive impact on the pace and volume of production and will attract more future investments.

It can be concluded from the aforementioned that operating under Production Sharing Agreements is not the optimum solution for large-scale deepwater gas projects. Although EGPC and EGAS are trying to avoid the disadvantages by introducing some changes appropriated from different systems, this nonetheless usually complicates Production Sharing Agreements—which are not designed to accommodate such changes—and increases investment risks.

If the real focus in the near future shall be on prospecting and development of gas from the deepwater in the Mediterranean, as a promising area for more giant discoveries, and if the government is going to pursue deregulation of the gas market, it is time to switch from Production Sharing Agreements to the tax/royalty system.

If the Ministry of Petroleum is apprehensive of the loss of any benefits by relinquishing the production-sharing agreement, the ministry should rest assured that the tax/royalty system would provide more benefits.

Nagy Iskander is a graduate of the Faculty of Engineering at Ain Shams University, and completed a master’s degree in international banking and financial studies at the University of Southampton in the UK. Over the past 20 years, his career has including positions as an economic analyst and negotiator specialised in gas projects in companies such as the US-based Amoco Corporation and in British Petroleum.

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