Overview

As we look forward to the release of the new model Iranian Petroleum Contract, Dentons' oil and gas partners James Dallas and Alistair Black analyse the contents of the recently released "Principles of the New Contract Model" (the Principles) and the possible implications for international oil companies (IOCs) looking to invest in this very promising jurisdiction.

What to expect

The release of the eagerly awaited draft Iranian Petroleum Contract model (the IPC) has received a significant boost in light of the outcome of the recent Iranian elections in February. Up to this point there has been little clarity as to whether the new model contract (originally announced during a conference held in Tehran in November 2015) would be officially released, after a series of protests from hard-line political rivals of President Rouhani threatening to obstruct its passage through the Iranian parliament (the Majlis). A coalition of centrists – a diverse group of reformists, moderates and pragmatic conservatives – have made significant gains against conservative hardliners in the recent elections to both the parliament and the 'Assembly of Experts'. This shift towards a more centrist political position and the increased representation for moderates in both houses is expected to consolidate President Rouhani’s hold on power and put him in a stronger position to seek a second term in 2017. The new parliament’s alignment with the President is likely to lead to greater consensus over economic policy, foreign investment, implementation of the JCPOA and reforms to legislation and regulation affecting upstream (both exploration and production) activities in the oil and gas sector, including the IPC.

The Principles acknowledge many of the criticisms levelled at the previous buy-back contracts, and explicitly recognise the need for the structural reforms necessary to encourage investment of approximately $185 billion required over the next five years to modernise Iran's ageing oil and gas infrastructure. Key Iranian stakeholders (including the National Iranian Oil Company (NIOC)) and legislators (though, as noted above, the terms of the model IPC have not yet been approved by the parliament) have been responsive to these calls for change, and have sought to draw from the experiences of regional neighbours in specific areas (e.g. the Iraqi "technical service contracts"), whilst innovating in a number of others. 

Three key themes emerge from the Principles – a focus on collaboration, embodied through the use of incorporated/unincorporated joint ventures (and reflected in a new remuneration model that incentivises efficiency and enhanced production); a clear emphasis on technology transfer and the dissemination of technical know-how into the wider Iranian oil and gas industry; and a simplification and consolidation of the various model agreements currently used into a single document intended to cover exploration, development, production and providing plateau/enhanced recovery maintenance options (including additional fee incentives for enhanced oil recovery). 

What has changed

Cost Recovery

Far and away the most frequent criticism of the previous buy-back contract relates to the capped cost recovery regime. IOCs were previously expected to invest in the development of contract areas in the knowledge that any overrun beyond pre-determined budgets would be irrecoverable. This acted as a clear disincentive to invest in more risky or marginal prospects, particularly when combined with a limited remuneration structure that did little to reward enhanced productivity (explored in the section below). The Principles suggest that the new IPC will do away with these limitations altogether, and implement the following key changes:

  • full recovery of costs amortised over a five to seven year period (which itself can be extended if insufficient to recoup these amounts), with annual repayments (for both costs recovered and service fees) limited to 50% of total annual revenues derived from production within the relevant contract area. The extended repayment horizon is further backed by a hard obligation to reimburse the contractor in full where the relevant contract area will not yield sufficient revenues to permit full cost recovery over its production period;
  • the remuneration of finance fees during the amortisation period (capped at a relatively modest LIBOR+1%), together with any indirect fees associated with development including income tax, customs duties and social security payments etc. This contrasts with IOCs' experience in Iraq, where finance fees are not recoverable;
  • the original fixed cost regime is replaced with a more standard annual work programme and budgeting process, implemented through the committee procedure set out in figure 1 (Management Structure),  which involves approval from both the Joint Steering Committee (JSC) and NIOC. There remain a number of concerns over how tightly cost control is implemented through this process, particularly during the exploration phase – the Principles indicate that the IPC will mandate "Minimum Obligations", which delineate technical and operational requirements during this phase and will also specify a hard USD commitment in pursuing these (though note that nothing prevents the contractor and NIOC from agreeing additional financial and technical commitments in addition to the Minimum Obligations, with any such budgets/requirements agreed through the committee process held firm thereafter). The Principles indicate there will be limited cost overrun flexibility once these figures have been approved through the committee process, with a flex of no more than 5% during production (though this will incur a penalty applied to production fees), whilst no cost overrun is permitted during the exploration and development phases, unless mutually agreed by both the JSC and NIOC as a result of changes in either scope or target.

Fee Structure

A further historic criticism of the buy-back regime relates to its remuneration structure. Contractor fees were linked to a fixed percentage of the capital costs incurred (up to the budgeted cap) – this regime neither provided any incremental revenue for exceeding production targets, nor provided any upside associated with oil price increases. The Principles indicate that the new IPC will implement a true volumetric fee structure, which will extend over the life of the agreement (up to 20 years in the case of successful discoveries leading to production, with possible tail extensions of up to five years where enhanced oil recovery (EOR) techniques can be implemented). The pricing structure appears to be more sophisticated than either the Iraqi model or the previous buy-back regime, but the Principles do not set out a comprehensive exposition (or any worked example) of how fees will be calculated; there remains therefore a degree of uncertainty on how exactly the remuneration is determined. Based upon the information provided, we surmise the following elements will influence the Contractor's remuneration:

  • a base fee is payable per barrel/mcf of production and the fee itself is now linked to market prices. There is no indication of what percentage of market price will constitute the base fee and whether this percentage is to be 'bid' by each IOC (for further analysis, please refer to the section entitled 'Tender Model' below). There is also a "cap" mechanism to prevent windfall IOC profits from unexpected commodity price surges; again, the Principles suggest this cap will apply when the rolling average market price exceeds the market price as at the date of first production by a certain pre-defined percentage threshold. However, the Principles  do not specify what this percentage will be, nor (perhaps unsurprisingly) does it indicate whether a similar "collar" will apply to protect IOCs during low price periods (as low prices will also extend the amortisation period for recovery of costs);
  • the base fees are subject to additional multipliers per barrel/mcf to incentivise the exploration of high risk contract areas (ranging from 1x for low risk fields through to 1.5x for high risk onshore/offshore single or unitised fields). A separate fee multiplier also applies to brownfield sites (or greenfield sites to which EOR techniques have been applied) designed to reward incremental production increases, again acting as a multiplier to the volumetric base fee (1.2x at the low end for increases of up to 20,000 bpd and increasing in bands up to a maximum of 1.5x where production increases by more than 100,000 bpd). The Principles do not indicate whether there will be additional variations to the pricing benchmark for fields producing heavier grades;
  • there is also an "R" factor adjustment mechanism, which is calibrated to adjust the fee payable to the IOC based upon (i) the level of production of the field and (ii) the ratio of costs recovered against revenue earned. The latter calculation is dependent upon the multiple by which revenues received by the IOC exceed total expenditure incurred in respect of that contract area (with a ratio of revenue to expenditure <1 receiving the highest banding, and areas with a ratio of revenue to expenditure >4 receiving the lowest). Within each band there are further tiers which vary based upon daily production rate (with the lowest producing fields receiving the highest banding within each tier). It may be assumed that as contract areas mature, they may move down the differing bands (from A1>E4) as both output and the recovery ratio increase;
  • whilst no cost recovery is permissible if exploration of a contract area is unsuccessful (i.e. contractor takes full exploration risk), the Principles do indicate that participants may be given preferential treatment in the allocation of adjacent or subsequent exploration opportunities;
  • without any worked example, the interplay between the various adjustment criteria is uncertain. The Principles suggest that the fee is payable for each barrel/mcf produced, irrespective of whether the 'value' of those hydrocarbons will be allocated towards cost recovery (akin to the Iraqi model, where a fee is payable for every barrel produced). In addition, it is not clear in what order the various fee adjustments will be applied (whether the base fee is first uplifted by the 'field risk' or 'R' adjustment factors). 

Notwithstanding these concerns, the combination of a more robust cost-recovery regime, together with a move to a true volumetric tariff (together with additional incentives for incremental production) should provide a much stronger incentive to invest in the technology necessary to optimise production in Iran's green and brownfield reserves.

Joint Venture Arrangements

Perhaps the most important structural change embodied throughout the Principles is the shift to a joint venture model. This is driven by Iran's objective of facilitating a transfer of technology and know-how, particularly that required for modern EOR techniques which are lacking within the indigenous industry. IOCs are mandated to partner with either NIOC or a local designated entity by way of an incorporated/unincorporated joint venture structure, although the Principles provide little detail as to how ownership interests are to be determined and the timing and extent of such participation. It is not clear at what point during development a local party can elect to participate, and the nature of its contribution (whether  technical, financial or both). Unusually, decision making thresholds appear disaggregated from ownership interests and the funding structure – at all times, the IOC is expected to fund both its own costs and its development partner's carry throughout each stage of exploration, development and production. The management structure of this joint venture company is complex (perhaps unnecessarily so) and varies by phase of exploration/development as follows:

  • during exploration, the IOC acts as operator and retains control over day-to-day issues, but control over a number of operational issues is escalated to the Joint Exploration Committee (JEC) comprising equal members of both the IOC and NIOC. All decisions are to be taken unanimously, although key issues are ultimately determined by NIOC including the composition of final reports and statements, any changes to project targets and the determination of commerciality (which is subject to expert referral where the IOC/NIOC disagree – please refer to the section titled 'Commercialisation' below for further analysis);
  • during development and production, operations are implemented through a "contractor" JV company, and major decision-making is assigned to a joint steering committee (the JSC) with equal representation for NIOC and the IOC, with annual chairmanship alternating between NIOC and the IOC. In case of deadlock, any prevailing position on the issue in question will remain valid. The JSC and NIOC have combined oversight/approval of the Annual Work Plan and Budget (AWPB);
  • operations will be implemented by a Joint Operating Company (JOC), owned by the IOC and NIOC and possibly including an Iranian third party (exact shareholdings are not specified in the Principles, and are to be decided on a case-by-case basis) – potential issues arise with respect to (i) the possible mismatch between ownership of the Contractor and the JOC (and subsequent misalignment of their respective commercial interests); (ii) the technical competency of these local companies, and (iii) any potential direct or indirect links to sanctioned entities, including those affiliated with the Iranian Revolutionary Guard Corps (IRGC). As per the JSC, annual chairmanship/appointment of the Managing Director alternates between NIOC/local party and IOC appointees in equal measure (initially defaulting to NIOC appointment of Chairman and IOC appointment of the Managing Director). The remaining board members are appointed by both parties, with more members going to the IOC.

The management structure outlined in the Principles is broad-brush, and more detail will be required in the IPC model before any definitive conclusion can be made. At this stage, the disaggregation of decision making from ownership and funding obligations is at odds with the more established JOA/PSC models more commonly used throughout the industry. In particular, more information is required concerning the criteria used for the determination of commerciality – an IOC would ordinarily relinquish a non-commercial prospect and cannot

be expected to inject capital into a marginal prospect without having a complete commercial understanding of its overall economic recovery (including eligibility for uplift fees). 

Areas of uncertainty

Whilst the changes suggested by the Principles do address a significant number of the key concerns levelled at the previous buy-back regime, there remain certain areas where the Principles are either silent or where more information is required to develop a complete understanding of the proposed risk allocation.

The Tender model

The Principles provide little indication as to the nature of any evaluation criteria that will be used to select successful bidders. The fee per barrel is market linked – absent of any direct confirmation, we believe that the primary selection criteria may be the percentage of market price 'bid' by the IOCs as their base fee per barrel/mcf for each tender. Given that the 'field risk' adjustment factor referenced in 'Fee Structure' above is largely pre-determined, and the production plan is jointly agreed as part of the overall Development Plan, it is not clear on what other bases bidders will differentiate themselves (for instance, under the Iraqi model, both the fee per barrel and production targets are treated as key tender metrics). We doubt NIOC will select candidates primarily on the basis of a technical evaluation, and believe there could be other commercial criteria not set out in the Principles which can also be bid upon (for instance, the flexibility to tender higher or lower fee adjustments corresponding to each step change in the 'R' index, or perhaps (for greenfield contracts) the provision of hard financial commitments to "Minimum Obligations" during the exploration phase)? The nature of these evaluation criteria might also be expected to differ based upon the nature of each prospect (whether greenfield or brownfield), but this is not addressed. One possible alternative is that a number of the smaller IPCs will not be tendered publicly (a waiver is possible under local tender law, provided various government bodies consent). We also note that the Principles do not provide for any type of grandfathering or suggest any kind of alternative treatment for prior concessionaires under the previous buy-back regime, which we assume will mean that a dual system of buy-back contracts and IPCs will subsist for a certain period.

Management structure

Whilst the adoption of a joint venture structure is preferable to the previous risk services model, the disaggregation of the IOC funding obligations from the ownership and voting mechanism is potentially problematic (particularly given the IOC's obligations to fund all exploration and production, together with NIOC's/local designated party's percentage share of carry through such phases). Issues arise in a number of areas, most notably:

  • the technical competence of third party "designated" Iranian companies and any associated sanctions for potential IRGC links; to date, no guidance or non-exhaustive list of such participants has been provided so that bidders can perform initial "know-your-customer" checks or evaluate both technical/financial capability and establish the degree to which the IOC will have to "carry" (in both a financial and commercial sense) its joint venture partners. This issue is exacerbated by the lack of detail in the Principles as to how ownership interests are to be determined and the timing and extent of the NIOC/local party participation in each contract area – it is not clear at what point during the development cycle these parties can elect to "back-in", nor is there any guidance as to the precise nature of their involvement (i.e. whether they will be carried or elect to provide technical or financial assistance); 
  • the overall management structure requires further detail; in particular, during the exploration and development phases, IOCs need clarity as to which decisions must be escalated to either the JEC or JSC and (ultimately) NIOC (given the potential for delays). The Principles simply provide an overview of the appointment of key personnel and outline certain categories of decisions which will require escalation. For instance, during the exploration phase, there is a limited, non-exhaustive list of topics requiring NIOC escalation (including any determination of commerciality – discussed below), but this does not inspire confidence that day-to-day operations will not be delayed due to unnecessary intervention by the JSC/JEC, or whether joint venture partners will be able to interfere in the IOCs development activities (over and above the determination of the AWPB and Development Plan through the committee process). The key issue is not directly addressed; namely, whether either NIOC or the local party can "direct" the IOC to implement activity which it would otherwise not perform (e.g. increasing compression for EOR). The composition of the board and manner in which the chairman is appointed suggests that this is a possibility, with the two main mitigants for such risk being (i) cost recovery and (ii) the ability to refer such decisions to arbitration (although please refer to our comments on arbitration in Iran below);
  • the Principles provide no guidance as to whether the designated local partner will be party to a joint operating agreement with the IOC (and if so, whether this will be on a standard form). If there is a "standard" local JOA (and multiple IOCs are involved in a single contract area), it has been common practice under the Iraqi model to limit a local partner's power to veto decisions by introducing an "offshore" JOA between the IOCs to align their voting.

Commercialisation

We understand that the first draft of the model IPC will provide a set of "objective" criteria by which commerciality is to be judged – the Principles give no guidance other than saying the 'automatic formula' for determining commerciality should secure the main concepts of "Viability of development of the discovered fields both technically and commercially at the best possible market prospects". These criteria are of paramount importance, particularly given that NIOC will initially determine whether a find is "commercial" (this discretion is subject to referral to an expert should the IOC disagree, but there is no mention of who will appoint the expert).

It is not clear why NIOC needs this level of control – under a standard PSC/JOA model, an interest holder relinquishes an area if it believes a field to be uneconomic (and such licence/interest becomes free for other parties to explore, which should satisfy the Ministry of Petroleum's main concern in allowing a field to be developed where the incumbent is not prepared to do so). Given the "objectivity" of these criteria, and the fact that  the IOC must fund all stages of exploration, development and production, this need for control appears redundant – an IOC will be strongly motivated to reach commerciality, particularly where the proposed fee structure provides incentives for prospects that may be marginal initially.

Remuneration structure

The Principles are largely silent as to the mechanism by which the Contractor/IOC's entitlement to cost oil and service fees will be delivered. Presumably, this will follow a similar model to that in Iraq by reference to a lifting contract or long-term services contract with the Ministry of Petroleum/NIOC, which will in turn instruct its marketing entity to either deliver or sell equivalent volumes of oil/gas and reimburse the IOC. A number of contractual issues arise, primarily relating to privity (given that the lifting agreements are typically entered into with the government, whereas the marketing company is normally a separate legal entity), and what recourse an IOC has if the relevant marketing entity does not deliver on its obligations. In Iraq, this was addressed by way of framework agreements entered into between the government, the marketing entity and the IOC to minimise potential "intervention", provide direct recourse to each party and automate the payment process to the fullest extent possible.

IOCs should also be mindful of whether Iran's oil and gas export infrastructure has the capacity to throughput sufficient volumes to allow NIOC to maintain its payment obligations once a number of additional fields come onstream. This may not be problematic at the outset, but could manifest if there is not a commensurate investment in mid/downstream infrastructure as volumes increase.

The previous buy-back regime also implemented a broadly similar payment scheme (the Contractor was obliged to enter into a form of lifting agreement with NIOC to purchase petroleum, the value of which was offset against sums payable to it under the associated buy-back contract). A number of historical concerns around how this mechanism was implemented may also apply to the IPC. Notably, the petroleum that was sold had to come from the field that was developed by the Contractor. It was not possible for a contractor that was developing a number of fields in Iran under different service contracts to aggregate production from all such fields and reduce the risk that insufficient petroleum was available in any one of them. Moreover, the sales agreement could not exceed 15 years and could not be for more than 50% of the production from the field during the contract period – this maximum period applied even if production was suspended as a result of force majeure or a change in law.

Reserves and lender security

The Principles unequivocally state that "Underground Hydrocarbons" still belong to the Iranian State and cannot directly be booked on balance sheet. However, there is potential room for manoeuvre as the Principles also provide that both the Ministry of Petroleum and NIOC have express authorisation to deal in "above ground hydrocarbons" (i.e. oil/gas/condensate that has been lifted). Again, following the Iraqi model, IOCs were able to effectively "book" certain reserves by reference to their contractual entitlements under these lifting agreements.

This relaxation for "above ground hydrocarbons" suggests that IPC participants could grant lenders effective security from the wellhead by assigning their rights under the IPCs and marketing/lifting agreements. 

Pricing model

Whilst the volumetric fee structure is a very significant departure from the precedent buy-back contracts, remuneration is still largely based upon a risk services model rather than any true entitlement to underlying hydrocarbons. 

Ultimately, it is a matter for IOCs as to whether this provides sufficient economic incentive to invest in exploration and production, particularly given the cap mechanism applicable to the service fee itself, which potentially limits "positive" market exposure whilst still leaving IOCs exposed to low price risk (given the omission of any explicit collar). Much will depend upon the precise detail of how the base fees and range of incentive fees will be calculated (particularly the risk multiplier and how contract areas will be categorised according to this risk).

It should also be noted that the split ownership structure of the JOC and the Contractor will, we understand, entitle either NIOC or the designated local company to its "pro-rata" share of service fees after recovery by the IOC of its own share of cost oil and carry. Given that the pro-rata share (determined from the outset) is not linked to financial or technical participation in the contract area, this may serve as a further disincentive to investment.  

Cost recovery

Whilst the cap on costs imposed under the previous buy-back arrangements is greatly improved, there remain a number of more minor concerns to be addressed in the model IPC. Recovery of cost oil and the payment of all service fees is limited in aggregate to 50% of annual production – while this is broadly in line with other local jurisdictions, in certain circumstances contracts for high risk/unexplored fields allow payment of costs and fees out of a higher proportion of production and a similar approach may be appropriate for some Iranian fields (and conversely, this cost recovery percentage can also be lower in jurisdictions where it is sometimes used as a bid parameter). It is also not clear to what extent cost recovery is ring-fenced – it is assumed that IOCs will be able to recover all exploration costs across various fields within the same contract area (the uncertainty is caused by reference to the phrase "all costs incurred in successful discoveries", implying that only costs associated with the development of successful wells can be included).

Dispute resolution

Other than a dispute over the determination of commerciality (which is referred to an expert), all disputes are to be ultimately referred to arbitration, with a seat in Iran and applying Iranian law, which may be a cause for concern given the lack of familiarity many IOCs will have with this venue – this would be a particular concern for lenders where project financing is employed. It should be noted that Article 139 of the Iranian Constitution requires that the Council of Ministers and the Iranian Parliament must give their consent to any arbitration involving state assets where foreign parties are involved. There is also a further requirement that in "important cases" the approval of the Council of Ministers and Parliament must be obtained even if the parties to the arbitration are both Iranian companies. Iran has signed the New York Convention and various Bilateral Investment Treaties but these do not address the underlying need for such consents.

Local law issues

Contractors should also be aware of a number of key local law issues within which the IPCs will need to operate, which include:

  • statutory local content requirements – government entities (such as NIOC) may appoint a joint venture or consortium in which Iranian and foreign companies have an interest provided that the Iranian party receives at least 51% of the "work value" of the goods or services to be provided, the interpretation of which is untested;
  • issues involving arbitration over state assets (discussed immediately above in "Dispute Resolution"); and
  • whether the long approval and procurement process previously required for buy-back contracts (escalating through various stages to the parliament and the Council of Guardians) also apply to IPCs.