The Model Producing Oil Field Technical Service Contract (PFTSC): An Overview

The Model Producing Oil Field Technical Service Contract (PFTSC): An Overview

By Ruba Husari

Ms Husari is an expert on Middle East oil and the editor of iraqoilforum.com, a specialized website on Iraq’s oil industry and politics. This paper is an extract of a full analysis of the PFTSC to be published soon on iraqoilforum.com.

The model Producing Field Technical Service Contract (PFTSC) developed by the Iraqi Ministry of Oil to be used for the first bid round is a hybrid model contract to be added to more than 100 fiscal regimes that govern international oil companies’ participation in some 75 countries. Service contracts by definition generate the largest stake for the state where a 90% take is considered an accepted average, while at the same time they impose limitations on booking reserves under Securities and Exchange Commission (SEC) reporting rules, hence their attractiveness for countries with a strong nationalist tendency.

The complex contractual terms introduced in the PFTSC are the result of constraints dictated by the political environment and Iraq’s desperate need to remedy the producing oil fields from the ills of three decades of forced production with little reservoir management. The challenge it faced was how to stop the decline in the major producing oil fields – including Kirkuk which has been in production since 1934 and Rumaila, where the southern field came on stream in 1954 and the northern field in 1972 – and improve the recovery rates using enhanced techniques, while at the same time safeguarding state control over its wealth. The type of contracts Iraq used since nationalization, which started in 1972 and was completed in 1975, were limited to technical assistance contracts in the 1970s, production sharing agreements in the 1990s and a service contract called Development and Production Contract (DPC), based on the Iranian buyback contracts with a few improvements, that was introduced in 2000 and remained in place till the fall of the previous regime in 2003. This paper uses the DPC as the basis for comparison with the newly introduced PFTSC, both being service contracts, though the former was only used for green fields that were not in production as well as exploration blocks offered to international oil companies (IOCs) in the late 1990s.

Term Of The Contract

Unlike the DPC, which limited the term of the service contract to 12 years with a provision for an extension, the PFTSC is set at 20 years with the possibility to extend it by a further“maximum period of five (5) Years, subject to newly negotiated terms and conditions” (Article 3.3).   

The longer than usual term of the new PFTSC reflects an attempt by Iraq to compensate for other limitations introduced in the contract, especially on operatorship. However, though it might look like a concession to international oil companies (IOCs), it has some advantages to Iraq as the foreign companies remain engaged in the maturing fields, on the same contractual terms, once the currently producing reservoirs start to decline again and enhanced oil recovery techniques are needed to improve recovery rates.

Participation

Since Iraq’s first attempt at opening up its oil sector to IOCs in the early 1990s, the principle of participation has evolved significantly until the adoption of the 25% carried interest stake for the national entity in the PFTSC. Almost 20 years ago, the drafters of the earlier model contract made a provision for a national entity, at the time State Oil Marketing Organization (SOMO), to hold a 25% state in the production sharing contracts offered at the time. In the DPC, which was later used to sign exploration contracts (with ONGC, Pertamina, etc), the state stake was cut to 10% as a carried interest. During the early internal negotiations over the government entity stake, Iraqi oil officials debated different options and the earlier version of the PFTSC in late 2008 stipulated the government holds a majority stake of 51% in the project. As oil prices fell from their high of $140+/B in mid-2008, adding strains to the state budget, the interest of the state entity was dropped to 25% in the final version of the model contract to be carried fully by the foreign contractor.

Though they are partners at 25-75% in the final PFTSC, neither of the stake holders has any ownership of any resources nor are they in full control of operations. The foreign company (or consortia of companies) will finance 100% of the capex, opex and other expenditures (supplementary and training costs). Though it will be entitled to all petroleum costs paid as service fees and supplementary costs paid as supplementary fees, the state partner will be entitled to receive 25% of any remuneration fee paid.

Furthermore, when it comes to assets, the contract states that “all assets acquired and/or provided by Contractor or Operator, in connection with or in relation to Petroleum Operations, the costs of which are subject to recovery in accordance with the provisions of the Contract, shall become the property of ROC (regional oil company) upon their landing” in Iraq.

Development Plan And Phases Of Operations

Under the DPC, the contract was divided into three distinct phases with clear cut roles and distinctive roles for the national and the international companies at the different phases: a development phase of five to six years where the IOC is the operator, followed by a transitional phase of two-three years where the IOC still remains the only operator and a final phase of a maximum of three years where the national oil company becomes the operator. A provision is made for a technical assistance agreement with the new operator that could last up to 15 years following the handover of operations.

The development plan is also simple: a “conceptual plan” is agreed prior to the contract signature, followed by a “preliminary plan” and target scope of work to be approved within six months of the effective date. After an appraisal period of three years, a revision of the development plan and of the scope of work as well as a final development plan, are issued.

The PFTSC divides the contract in two phases: a rehabilitation phase of maximum three years followed by an enhanced recovery phase for the rest of the contract term, which should see each of the producing fields reaching its plateau within six years of the involvement of the foreign company and being sustained over seven years before the natural decline takes over. At the end of the term of the contract, operations are handed over to the regional oil company.

Dealing with producing fields with a different set of problems and unusual production profiles – production capacity is in decline for five of the six fields tendered in the fist bid round – the development phases are customary. Within two weeks following the bidding, the winning company or consortium must submit an overview of the proposed development approach outlining a description of the main drilling, seismic, and facilities engineering activities along with a breakdown of the expected production, operating and capital cost profiles throughout the term of the contract.

Within six months of the effective date, it must submit to the joint management committee a rehabilitation plan that includes:

·          A remedial program for the immediate and near-term actions to be taken “to halt any non-optimal operations, to arrest production decline and to achieve a sustainable and improved production rate” to be achieved as soon as possible after the approval date of the rehabilitation plan. The improved production target being a net production rate of 10% above the initial production rate at the time the contract is signed.

·          An additional appraisal program for the currently producing as well as the discovered but undeveloped reservoirs in the contract area, which require and justify further appraisal work, including a time schedule for geophysical surveys, geological and reservoir engineering studies etc. The additional appraisal program is aimed at acquiring technical data required to conceive the enhanced redevelopment plan.

Within six months after the completion of the additional appraisal program, but no later than three years from effective date, the contractor shall submit for approval the enhanced redevelopment plan, which shall upon endorsement by the regional oil company supersede the rehabilitation plan. The enhanced redevelopment plan aims at achieving the target production plateau for the plateau period from producing reservoirs only.

The PFTSC provides a provision for the discovered but undeveloped reservoirs to be developed and produced by the same contractor under the same contract but subject to a different set of remuneration fees to be agreed between the two sides. The relinquishment article in the PFTSC allows the contractor exclusive rights to negotiate and reach such an agreement within six years from the approval date of the enhanced redevelopment plan for those reservoirs that are not targeted in that plan or for which development operations have not started. If no agreement is reached within this period, which is set in the relinquishment Article 5 of the contract, it will have to relinquish those reservoirs to the regional oil company which shall be free to develop such reservoirs.  

Furthermore, the PFTSC gives the contractor an exclusive right, for a period of six years from the effective date, to negotiate a separate agreement to explore for and develop the undiscovered potential reservoirs, failing which the regional oil company will be free to explore and develop such reservoirs in any manner of its choice.

Conduct Of Petroleum Operations

Under the DPC a joint management committee (JMC) is established for the general supervision and control of petroleum operations and on handover, it is dissolved and a joint cooperation committee is established to function until the expiry of the contract. The role of the JMC is general supervision and control of petroleum operations while the contractor carries out all petroleum operations including studying, appraising and producing relevant reservoirs during the development phase of the contract – which includes achieving an early production target and a final production target – and during the transitional phase where the objective is to sustain the approved plateau rate. For 15 years following the handover date, the contractor provides technical assistance and services.

Not willing to hand over production operations in producing fields to a foreign company, a new concept of a field operating division (FOD) was introduced in the model PFTSC, acting as the operator of the field under the direction and supervision of the joint management committee (JMC). Before agreeing the final concept of the new operating entity, Iraqi officials contemplated setting up a field operating company for each field to act independently of the regional oil company and enter into a joint venture agreement with the foreign company. The idea was however dropped due to the legal complications of setting up such companies according to prevailing Iraqi law. The FOD is a “non-profit, unincorporated, joint operating entity, administratively and financially independent of the ROC.” It inherits the existing manpower units of each field and becomes detached from the ROC.

Although the FOD shall be established promptly after the effective date, it will only take over the conduct of petroleum operations after one year. In the meantime, for the purpose of insuring continuity of ongoing production, the ROC continues to operate the field for the first 12 months from the effective date, albeit under close coordination and consultation with the contractor and the supervision and control of the JMC. All costs incurred during the interim year are paid by the contractor and reimbursed as petroleum costs.

In trying to give the contractor responsibility over the conduct of petroleum operations but not the full decision making power, the roles and responsibilities of the three entities involved in the execution of the contract – ROC, FOD and JMC – become confused and intertwined in a manner that is bound to complicate operations on the ground and as a result the respect of the time frame set in the contract. Once ROC transfers to FOD the control of all facilities and equipment, it will continue managing and funding the common activities and facilities that remain under its direct responsibility but in coordination and close consultation with the FOD. Once the FOD has taken over the conduct of petroleum operations and has become the operator, the contractor supervises and controls, directly or indirectly through the JMC, all the planning, decisions, surveillance and day-to-day conduct of petroleum operations by the FOD. However it is the contractor who prepares and submits for approval the rehabilitation and enhanced redevelopment plans and all annual work programs and budgets and is solely responsible for achieving the production targets under the contract and is penalized for failing to perform according to the targets and timelines set in the contract. 

The phased approach to management is also bound to complicate the decision making process. During the first two years of operation, the FOD is managed by “joint managing directors”, one appointed by each of the contractor and the ROC. After the initial two years, FOD management falls into the hands of a general manager and his deputy, nominated initially by the contractor and ROC respectively with nominations alternating every two years. Managers of FOD departments are appointed by the general manager and his deputy, the former being the “chief executive officer” of the FOD.

The JMC itself consists of eight members. The ROC nominates four of them including the Chairman while the contractor nominates the other four including the Deputy Chairman and the Secretary. Decisions of the JMC are taken unanimously and where that fails, issues are referred to the senior management of the two parties.

Investment Costs And Remuneration Fees

The DPC offers a straightforward plan for investments and recuperation of costs and fees. The expected investment is initially agreed but revised after appraisal and expected remuneration is also agreed initially based on initial investment and other factors. Actual remuneration is computed as an agreed percentage of actual investment subject to a ceiling and floor, whereas cost is recoverable up to a maximum of 50% of produced oil from start of commercial production barrel to barrel, and remuneration is paid also from start of production up to a maximum of 10% of production barrel to barrel. Remaining costs and remuneration after handover are amortized over three years.

Under the PFTSC, there are different sets of cost and fees and different eligibility dates for payment. Spending by the contractor is subject to a minimum work and minimum expenditure obligations according to approved plans. He is entitled to:

·          Service fees comprised of: (1) petroleum costs; and (2) a remuneration fee.

·          Supplementary fees comprised of supplementary costs.

Petroleum costs are charged from the effective date but only due and payable after the service fee eligibility date. The remuneration fee can only be charged after this date. This service fee eligibility date is defined in the contract as “the earlier of the end of the rehabilitation period or the date when the improved production target is first achieved over 30 consecutive days provided that in no event can this date be earlier than the approval date of the rehabilitation plan.”

Furthermore, for any quarter the remuneration fee is calculated as the product of the remuneration fee per barrel applicable to such quarter and multiplied by the incremental production applicable to that quarter and subject to a performance adjustment. The fee is determined on the basis of an R-factor. According to the contract, the service fees due to the contractor “shall be paid without interest preferably in export oil at the delivery point or at contractor’s option in cash in USD.”

The concept of “supplementary” costs and fees was introduced in the PFTSC to take into account all expenditures made by the contractor that are not directly related to the conduct of petroleum operations. These include signature bonus, de-mining costs and additional facilities costs, expenditures incurred for remediation of pre-existing environmental conditions. The contractor starts charging supplementary costs from the effective date but they become due and payable according to a defined schedule. 

Supplementary fees due are also paid in export oil or, at ROC’s option, in cash, in US dollars. They are paid to the extent of 10% of the deemed revenues of the baseline production.

Conclusion

The PFTSC will be put to test for the first time by a consortium of BP and CNPC, who won a contract for the rehabilitation and enhanced development of the Rumaila oil fields in southern Iraq under the country’s first licensing round. However, the complex operational setup and the associated additional risks are unlikely to turn it into a template for the development of other Iraqi oil fields.

Copyright MEES 2009.