The Iraqi Ministry of Oil (MoO) prepared a complex contract commensurate with the structure and complexity of the Nasiriya Integrated Project (NIP), to be offered in a bid round scheduled for December 2013. Mindful of previous experiences and the importance of the NIP, the MoO offers a sweetening package hoping to attract enough international oil companies’ (IOCs) attention.
This contribution intends to shed light on the fundamental provisions that have bearings on the fiscal and financial aspects of the contract in comparison with those of the previous bid rounds. The paper begins with providing a brief background on the field and the bidding process, followed by assessing the main provisions, and ending with few concluding remarks. Texts written inside quotation mark “xx” are used by the MoO.
BACKGROUND ON NASIRIYA OILFIELD
The oilfield is located in the southern Dhi Qar Province and was discovered by the Iraq National Oil Company (INOC) in 1975. Its development however, was derailed by the Iran-Iraq war. The field came onstream in 2009 and was listed on the fast-track plan 2009-10, aiming to raise its output to about 50,000 b/d.
During the first half of 2009, ENI, Nippon Oil, Chevron and Repsol were invited, and submitted bids to develop the field on EPC contract. It appears that the Nippon consortium (Inpex and JGC Corporation) was preferred then but the negotiations broke down.
Accordingly, it was announced that the field will be developed through national efforts. However, in January 2011 the MoO formally announced plans to invite IOCs to develop the Nasiriya oilfield together with a refinery of 300,000 b/d in a bid round later that year. Again that did not materialize, but the idea of an integrated project began to gain momentum.
The Nasiriya refinery was listed in both the MoO Plan 2011-14 and in the National Development Plan 2010-14 with 300,000 b/d capacity, among four major new refineries, which in total could bring an additional 750,000 b/d of refining capacity. Also, the Integrated National Energy Strategy (INES 2013 – MEES, 14 June) recommended an export-oriented refinery to add value to crude oil and to diversify energy-related export offerings.
The four refineries were offered for international investors, but to no result. Foster Wheeler completed in May 2012 the FEED study for the Nasiriya refinery. Based on previous studies and a 3D seismic survey, it is estimated the Nasiriya field has 4.36bn barrels of proven reserves and the MoO is now targeting a plateau of 300,000 b/d.
The NIP bid round was finally launched on 1 November 2012, with the first workshop held in ‘Amman early April 2013, a second by mid-September, the Final Tender Protocol (FTP) will be known on 15 November and the open bid round is scheduled for 19 December in Baghdad. As of 16 August 18 companies and consortia had applied for qualification and the MoO approved 12 of them.
It appears the blacklisting policy against IOCs operating in the Kurdistan Regional Government (KRG) areas is maintained in the sense that the blacklisted IOCs will be barred from participating in the field development, as was the case with Total, but they could participate in the refinery construction only if they are qualified as a refiner.
FUNDAMENTAL CONTRACTUAL PROVISIONS FOR NIP
The contract, which comprises 43 articles, 8 annexes and 5 addenda, is complex due to its scope and related legal régimes, and law jurisdictions, extending over the three sub-sectors of petroleum industry: upstream (field development); midstream (transportation systems and export facilities for refinery products) and downstream (refining operations) comprising two refining trains – RT1 and RT2 each with 150,000 b/d.
In its attempt to lure IOCs the ministry offered many attractive terms: The contract duration is 25 years plus a maximum of five years, which is five years longer than previous Long Term Service Contracts (LTSCs).
The “Project Deemed Revenue” (PDR) prior to RT1 “Acceptance” means the value of any crude oil delivered to “Transporter”, while after RT1 acceptance means total value of the delivered refinery products. This definition raises several concerns.
First, the field development will be limited not only to a maximum production capacity, commensurate with the refinery nameplate maximum capacity of 300,000 b/d but it has to be phased with the refinery trains timelines. RT1 acceptance is expected to occur 78 months after the effective date, while no information provided for RT2.
These linkages raise two questions: (1) From prudent reserves management and maximum efficiency rate principles is this production level technically optimal for a giant oilfield with proven reserves of 4.36bn barrels (based on an estimated 26.9% recovery factor) and 16.2bn barrels of oil originally in place. (2) There will be a construction period between RT 1 acceptance and RT 2 acceptance. In the same period, field development progresses and thus more oil production comes onstream above the 150,000 b/d threshold of RT1.
The first issue here is that the defined deemed revenue does not provide the valuation criteria for this extra oil.
Second, the percentage formula linking IOC remuneration to PDR could, by intention or circumstance, prompt IOCs to delay or utilize a delay in completing RT1 to gain more remuneration on oil production, while the prime objective of the project is refining.
Third, PDR does not include revenues from associated gas utilization.
Fourth, according to MoO sources, the Nasiriya contractor would be allowed to export up to half the refinery output. In this case issues of domestic prices and subsidies for refinery products have to be incorporated in the pricing mechanism and in estimation of the deemed revenues.
IOCs’ remuneration is expressed as a percentage of the “Project Net Revenue” (PNR) and this is close to revenue sharing contract (a form of production sharing contract - PSC). PNR, for a given quarter, means PDR less “Project Costs” incurred in that quarter. PNR is considered zero when project costs exceed PDR for the same quarter.
The bidding parameter according to which IOCs compete minimizes the “Net Revenue Share” (NRS), and judging by previous bid rounds the MoO might have its anonymous maximum acceptable NRS. Accordingly, actual pre-tax remuneration shall be the product of the applicable NRS and PNR, adjusted for the R-factor.
Linking remuneration to project net revenue is a very significant fiscal advantage to the IOCs, since this would allow them to share the economic rent associated with the crude oil price, especially in the period prior to RT1 acceptance and to the efficiency of the refining operation thereafter. However, the remuneration would be reduced when the IOC fails to deliver the required oil to the refinery.
The contract provides elaborated payments’ cap and its commencement. Payment for “Project Cost” and “Remuneration” will be limited to 70% of PDR. These payments are interest-free and payable in oil or refined products or cash.
The 70% cap is higher, by 10 percentage points, than what was offered in the previous four bid rounds, except for al-Ahdab field, and thus the MoO provides another incentive to the IOCs.
There are two thresholds for payment commencement: (1) “Project Costs” shall be due and payable from the date when “Field Commercial Production” is sustained for 90 days at 150% on “Initial Production Rate”. But prior to “Refinery Final Acceptance”, recouping project costs is limited by the “Refinery Progress Limitation Amount”. (2) “Remuneration” becomes due and payable starting with the quarter following the quarter in which RT1 “Acceptance” takes place. Remuneration due and payable in any quarter shall be reduced by the “Field Production Deficit Amount”, and when this “Amount” exceeds the remuneration such remuneration shall be zero and the excess amount shall be carried forward into succeeding quarters until fully deducted.
The complexity of these provisions was necessary to ensure the construction of the refinery as planned. This is why the contract provides elaborated provisions on the critical path schedule to be issued each month to show progress of work associated with the construction and commissioning of the refinery.
PROJECT DEEMED REVENUE
Estimation of PDR and due payments requires clear pricing mechanisms for crude oil, refined products and utilized gas. While the MoO provides detailed provisions pertaining to oil price formula, market destination, marker crude and differentials for API and freights, no information was provided on the refined products price mechanism and other related matters. These missing items might be added later, probably until holding the second workshop of September 2013 and the FTP becomes ready.
R-factor is the ratio of cumulative cash receipts to cumulative expenditures in the conduct of project operations, and has direct implication for deciding actual pre-tax remuneration entitlement.
Current R-factor table has four levels of R-values with corresponding percentages ranging from 100% to 50% of the bidding parameter “Net Revenue Share Bid”. Once again, the MoO offers significant fiscal incentive compared to all other R-factor tables of the previous contracts except al-Ahdab.
The contract specifies minimum expenditure and work obligations and timelines for plans. Minimum expenditure obligation (MEO) is set at $400mn to be utilized within two years from the effective date.
This is the highest MEO so far among all concluded LTSC contracts reflecting the complexity and structure of this project. The corresponding minimum work obligations (MWOs) are outlined for the project’s three main components: “Petroleum Operations”; “Refining Operations”; and “Transportation Systems and the Export Facility [for refinery products]”.
Interim work program and related budget for “Project Operations” should be prepared promptly upon effective date; “Preliminary Integrated Project Plan” within six months from effective date; “Integrated Project Plan” for “Petroleum Operations” (oilfield development), no later than three years from the effective date; and finally, “Integrated Project Plan” for “Refining Operations” and the “Export Facility”, not later than two years from the effective date.
As was the case in the previous contracts this one comprises annual allocation for the Training, Technology and Scholarship Fund (TTSF).
But again the MoO makes favorable reduction compared with those for oilfields contracted under bid rounds one and two despite the fact that this project is complex technically and structurally, and thus there are more acute needs for training and professional capacity developments.
Similarly, this contract establishes an Infrastructure Fund (IF), first introduced in the exploration blocks bid round in an attempt to accommodate the concerns of the local communities. IF is managed and controlled by the MoO in coordination with the local authorities, and the allocations to the IF are recoverable and charged as project costs.
Comparing with exploration contract there are two main differences: First, the percentage now is much lower, and second this contract has two percentages instead of a unified one – and both are linked to “Refinery Final Acceptance”. Despite lower rate, the magnitude of annual budgets envisaged for this project would provide significant cash inflow for the IF.
The MoO offers two additional incentives by abandoning the State Partner and the signature bonus.
The assessment of other important items of financial and fiscal dimensions indicates similarity to previous LTSCs. These include taxes and related stabilization clause; production curtailment and take-or-pay practices; termination clause; arbitration; joint management committee (JMC) composition and decisions making; sub-contracts awards approvals; local supplies and services; environment impact assessment studies; and administrative overhead charges.
Finally, this is the first contract requiring compliance to the Extractive Industries Transparency Initiative (EITI) which is a welcoming positive development. That said, two remarks are due: First, such compliance should not be confined to the “price paid” but should include the volume of exported oil and generated export revenues; second, the compliance to EITI should be incorporated in the main contract since the new EITI standard adopted in May 2013 covers more issues in addition to export revenues. The MoO could consider the above and make the necessary amendment to the contract.
To ensure support for the project, it is vital to engage provincial authorities early and effectively during the pre-contracting phase. The project structure made the contract complex, comprising, as outlined above, many provisions that represent a serious departure from the contracts concluded so far.
This assessment also identified few ambiguities that need careful considerations by the ministry. Time is critically limited between now and both the planned September second workshop and the deadline for the FTP. But the current text of the contractual provisions needs serious rethinking and revision.
*Mr Jiyad, is the founder of Iraq/ Development Consultancy and Research (Norway).
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