Coping with the Zeitgeist… Seeking Solutions for Tomorrow’s Inevitable Complications

Over the past decade, the development of Egypt’s hydrocarbon resources has seen a significant quantitative rise. Investors lay their aggressive exploration and development strategies, and through intensified campaigns, they strive to achieve their desired targets. However, hydrocarbons are and will always be a non-renewable source of energy, which means the diminution of its resources, is inevitable. Egypt’s extant conventional petroleum resources are on the verge of depletion, and experts estimate another five to six years before Egypt’s finds itself at a juncture that necessitates the implementation of radical changes to the current regulatory framework to be able to resume upstream activities.

The majority of exploration and development operations in Egypt are concentrated in three geographical areas, namely the Gulf of Suez, the Nile Delta and the Western Desert. These areas have been producing both oil and gas for decades, and in spite of their current production levels, their reservoirs are on the fast track of progressive depletion and eventual exhaustion. Unanimously, investors consider the development of the Mediterranean’s hydrocarbon resources to be the only logical step forward.
Developing these new prospects is an extremely difficult task in itself and the rigidity of the current Egyptian agreements model, the Production Sharing Contract (PSC), adds an array of obstacles to an already complicated venture.

Limitations of the PSC Model in Exploration
At the forefront of the PSC restraints is the subject of cost recovery, an issue that continues to haunt the investor. Despite assumptions of all risk associated with exploration due to the terms of the PSC, the government’s involvement (represented in the EGPC, EGAS or GANOPE) is present from day one.

BP’s Exploration and Agreements Consultant, Mr. Samir Abdelmoaty, describes the complications that arise from the extent of government involvement, “When an investor is awarded a concession, he submits a letter of guarantee to the government, covering the estimated cost of the exploration operation. In addition, he has to obtain the government’s approvals on the budget and work program of the exploration venture.” In the case of leftover capital from the agreed-upon budget for exploration (shortfall), it is paid back in cash to the government.

Operating under the assumption that a discovery will be found and commercialized, the investor would technically be spending the government’s money on exploration.

Limitations of the PSC Model in Development
Once the discovery is in the development stage, the investor begins recovering the cost of the exploration operation.
Here is where the issue becomes complicated; the government has several conditions to approve cost recovery, some which can sometimes limit the scope of what the investor can and cannot do.

All services have to be chosen through tenders; the investor has to contact all companies registered with the EGPC, create a shortlist of successful technical bidders, and then financially assess every offer and choose the most economical one. The investor must then obtain approval for tender documents and list from the EGPC, offer the tender, and assess the offers in the presence of the committee from the EGPC.

Each party conducts its technical evaluation agreement on a list of qualified bidders. Finally, both parties choose the company according to the most economical financial offer.
In this process, the technical assessment is usually a difficult and time-consuming negotiation. The investor sets certain technical specifications that can sometimes only be found in one bidder. The government however requires the investor to have more than one bidder to choose from, even if they do not meet the requested technical specifications.

Cost Recovery is usually paid from the production of the discovery, which is considered national capital. Hence, it goes through several rounds of auditing from the EGPC and the Central Auditing Organization (CAO), who meticulously review every spending to make sure it is cost-effective. Furthermore, any expenditure has to be approved by the government, even if it’s worth a meager $1000. This thick bureaucratic procedure is very time-consuming for the investor, which translates into financial loses. Matters could become worse if there are differences on technical matters between the investor and the government, leading to further delay of obtaining approvals.

The government imposes a ceiling on the salaries of employees, which is quite counterproductive when seeking highly skilled labor in a global industry. Egyptians for example have a certain fare that, if exceeded, is excluded from the cost recovery.

Every bill is audited by the EGPC and often times there are disagreements between what the investor believes is needed versus the opinion of the EGPC. Sometimes officials are reluctant to grant approvals and thus resort to forming a committee, which has to unanimously approve the request. If the decision is not unanimous, the request is rejected.

Mr. Abdelmoaty comments, “Cost recovery has become an extremely long and time-consuming process for both the investor and the government. There are full departments on each side whose sole responsibility is working out the intricacies of cost recovery … for the investor, time is money, and the time spent in recovering operational cost ends up costing the investor more.”

Why Eliminate Cost Recovery?
Zero cost recovery is not a new issue. It has been exhaustively discussed numerous times before. One option is using a hybrid model, one that combines both aspects of the PSC and the Tax Royalty systems. For example, instead of paying the investor 30% or 40% cost recovery in addition to the 20% to 30% profit-split, the equation can be readjusted where the investor assumes all the cost, but also reaps all the profit.

Other experts favor shifting the system to Tax Royalty completely, especially in the cases of deepwater exploration and development; these operations require highly sophisticated technologies that exist on a very small scale in Egypt.

Deepwater and deepwater horizons, especially High Pressure High Temperature (HPHT) targets, are extremely problematic and incredibly expensive.

The nature of the Mediterranean’s reservoirs is different from those located in the Western Desert or the Gulf of Suez. They are narrow channels that require drilling a multitude of wells vertically to extract the maximum amount of natural gas. Moreover, HPHT targets require special equipment that can sustain the extremely high temperature and pressure; these tools and technologies are exceedingly expensive. Therefore, seeking approvals through the bureaucratic channels for such pricy equipment and technologies is simply unsustainable under the PSC model, which is why it needs to change.

The government has to encourage investors to utilize new technologies, which are usually expensive. Obtaining approvals of such technologies is a difficulty for the investor; if the official has technical background and understands the significance of the technology, he will no doubt approve it. But if he is viewing the issue from a monetary perspective, he is likely to deny the approval.

According to Mr. Abdelmoaty, “There is no standard system for such approvals; it usually depends on the individual granting the approvals at that specific time … the current agreement model needs to be amended because the majority of the problems are results of cost recovery.”

Benefits of Various Agreement Models
The aforementioned hybrid model was applied before, where the government allowed the investor to bare the costs of E&P in exchange for a share of the production. The investor would extract the hydrocarbon and the government would buy it at a specific price.

After estimating the reserves of the reservoir and the cost of production, the investor calculates the needed Internal Rate of Return (IRR) and accordingly decides on a price for the gas. Four years in, the investor returns to the price negotiation table, assess the actual cost of operations, the actual reserves of the reservoir and accordingly modify the price.

If the operation cost is more than estimated, the price then rises and vice versa. Same with the estimated reserves, if they are higher than initially assessed, then the price is dropped.
The government can allow the investor freedom yet set strict deadlines for delivery of production to deliver a specific amount; if none of the deadlines are not met, penalties can be imposed, which could reach the loss of the concession if need be.

When investors take on the full operation of exploration and production, they can benefit from the global deals they have with services companies rather than going through tenders that favor low cost over quality. Moreover, HPHT requires very skilled labor that is not available everywhere, and recovery of HPHT cost is simply unrealistic due to how expensive these operations cost.

A high-ranking source in the EGPC explained the current model of agreements cannot be modified simply since it has its roots in the law, which is the parliament’s prerogative. Any radical changes to the model are not likely to be approved due to the inexperience of the Parliament’s Energy Committee. The source gave an example of a recently discussed bill in the parliament intended to raise taxes on the investor, which was later dismissed because it would negatively affect the Egyptian government more than the investor.

The PSC has been a tremendously successful model for a long time and still remains. However, there are cases where the PSC model is simply unsustainable. Looking forward, the number of those cases will inevitably increase, which is why the government should be amenable to alternative solutions, ones that balance and maintain the sovereignty and right of the state while allowing the investor more freedom to operate more efficiently.

By Mohamed El-Bahrawi


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