International interest in Iran’s reform of foreign investment in the oil and gas sector has grown during the last nine months, as was no doubt hoped for when the principles underpinning the reforms were first announced in November 2015. Details about the reforms are scarce. However, the wait might soon be over and some expect the first post-reform projects to be awarded before the end of 2016.

In this article, we look at what is known about the terms of the new Iranian Petroleum Contract, discuss how it will differ from the incumbent ‘third generation’ buyback contract and consider some key implications for IOCs.

Foreign participation wanted

The oil and gas sector is significant for Iran; economic activity and Government revenues depend on it. And Iran’s hydrocarbon reserves are significant for the world; its reserves are fourth for oil and second for natural gas. However, to achieve its potential on a global scale, Iran’s oil and gas sector needs two things – foreign investment and foreign technical expertise.

Iran hopes to attract around USD 200 billion of foreign investment over the next 5 years. That's USD 40 billion per year, an eye-watering amount given most IOCs have slashed their capital budgets in response to low oil prices in an oversupplied global market. Of the USD 200 billion, USD 130 billion is needed to meet upstream capital demands with USD 70 billion going to downstream sectors, including petrochemicals.

Iran also hopes to make the sector more efficient by deploying technologies not already used domestically, particularly improved oil (and gas) recovery (“IOR”) and enhanced oil (and gas) recovery (“EOR”) techniques. These technologies are critical for Iran to maximise the economic function of its oil and gas resources.

Bye-bye buyback; Hello IPC

Iran has been using various iterations of the buyback contract for around 25 years. However, this model is regarded by many as being uncommercial. Participating IOCs did not usually commit significant resources to the sector or undertake riskier developments. Many that did endured losses or broke even. As a result, the buyback contract could not be relied on to attract the level of capital inflows and technology transfer required to expand the sector.

The need for these concerns to be addressed has been recognised and a new model has been developed – the Iranian Petroleum Contract (“IPC”). The Iranian Government, the National Iranian Oil Company (“NIOC”) and key stakeholders (including downstream and related industries) will be relying on the IPC to herald a new age of growth.

The IPC was announced during the “Oil Show” in Tehran at the end of November 2015. The general terms received approval from a government economic advisory body on 12 July 2016, followed by Cabinet approval (by Council of Ministers resolution) on 3 August 2016. A model form of the IPC is expected to be finally approved and released imminently.

The word ‘new’ should be used with some restraint when describing the IPC, however, as both the buyback contract and the IPC are both “risk service contracts”. In the oil and gas industry, a risk service contract is understood to principally involve: a contractor funding exploration and development capex in return for the right (if it is successful) to recover its costs and to earn a fee, either in cash from production revenues or in-kind.

We know the principles, but not the terms

Even once the IPC is released, the precise terms of the IPC will require negotiation on a case by case basis. However, the principles on which those terms will be based are now relatively well understood.

The Cabinet approval sets out the general terms, structure and model for upstream oil and gas developments. It is a further meaningful insight into the government policy that is driving the foreign investment reforms, which could be wider than initially expected. This is because the Cabinet approval notes that there will be two IPC categories for brownfield projects. This is particularly significant for at least three reasons:

  • the brownfield contracts will potentially allow IOCs to participate for lower cost and lower risk (leveraging specialist proprietary applications) whilst having a more immediate impact on production;
  • they will potentially apply in respect of fields not otherwise offered to IOCs or which may previously have been subject to buyback contracts; and
  • if widely implemented on existing projects, they will broaden Iran’s reform of a critical domestic industry.

So, what are the key differences?

Whether or not the IPC achieves Iran’s objectives by attracting foreign participation, the IPC will almost certainly improve the investment conditions for IOCs in many areas. We have summarised these improvements in the following table.

Requirement

Under Buyback

Expected under IPC

Contract type

Risk services contract

Risk services contract

There will be three IPC categories: one for greenfield projects; a second for brownfield projects; and a third limited to IOR/EOR at brownfield projects

Contractual relationship

IOC is contractor providing services to the NIOC (or its subsidiary)

IOC and the NIOC or its nominated subsidiary are joint venturers

Joint operating company is contractor

Operator rights

IOC is operator during development

NIOC is operator during production (no IOC participation)

IOC is operator during development

Joint operating company is operator during production (IOC directs management)

IOC remains liable for joint operating company’s conduct

Term

Up to 7 years, no extension

Up to 20 years with 5 additional years for IOR/EOR

Nature of IOC interest

No ownership of project assets

No ownership of project assets

No right to oil or gas in reservoir

No right to oil or gas in reservoir

No right to actual oil or gas production

IOC is expected to have a right to oil and gas production, but only once lifted

IOC cannot book reserves

IOC is expected to be able to book reserves

Budget and work program

Budget and work program approved by NIOC at or near start of contract

Budget and work program submitted by IOC for approval by joint steering committee

NIOC has ultimate approval right

Budget is fixed in respect of approved work program and IOC assumes risk of cost overruns during exploration, development and production

Annual changes to budget and work program are expected to be permitted, subject to NIOC approval and a 5% cap during production

Increases to approved budgets are expected to result in contractual penalties

Cost recovery and remuneration

Exploration and development costs are amortised over 5 to 7 years (with no extensions)

Exploration and development costs are amortised over 5 to 7 years (but can be extended if cost not recovered)

Production costs (including for capital works) are amortised

Remuneration is by fee only

Remuneration is either by fee or in-kind

Where an IOC elects ‘in-kind’, the Minister of Oil can nevertheless direct the fee is payable if the relevant in-kind quantity is needed for domestic consumption

Cost and fee recovery capped at 50% of crude production

Expected that cost and fee recovery will be capped at 50% of crude production or 75% of gas production

Total recoverable amount capped at commencement

Total recoverable amount not capped at commencement, but regulated by budget

Fee structure

Fee based on fixed percentage of production revenues

Expected to be a volumetric fee (per barrel or per thousand SCF for gas) subject to a cap determined by a market reference price

Fee is not adjusted, although the fee may be decreased by NIOC unilaterally

Base fee will be adjusted by ‘R’ factor (ratio of revenues to costs) and production rates

Base fee may be adjusted further as part of incentives regime (ie, a percentage uplift on the base fee)

Incentives

No incentives or ‘upside’ sharing

Incentives are paid for certain projects (high-risk, brownfield, smaller fields)

Incentives are also paid for IOR/EOR projects

Local content

51% of value to be awarded to local contractors

Expected that much higher proportions must be awarded to local contractors

Executive management roles are to progressively transferred from IOC nominees to nominees of local companies

Impact of NIOC curtailment decisions

Less revenue available for IOC to recover costs, IOC carry risk

IOCs will still be entitled to recover costs and fee payments (by extending recovery period)

Failure to meet minimum production

NIOC controls production

Consequences include non-recovery of cost and fee

 

Joint operating company controls production

Consequences of production shortfalls against targets are not clear

Consequence of inadequate production include non-recovery of cost and fee

Marketing

No marketing by IOC

Expected that IOC may have marketing rights in respect of lifted quantities if in-kind cost recovery is elected

Sanctions ‘snapback’

By implication, no protection from international sanctions

Expected to be an express requirement; no protection from application of international sanctions

Dispute resolution

Escalated negotiations finally resolved by arbitration

Escalated negotiations finally resolved by arbitration

What won’t we know until the IPC is released?

A lot. There are a wide range of matters that will not be known until the IPC is released and, even then, until after bidding and negotiating for specific projects has occurred. And complexity comes with detail. Although deep speculation about all of these matters could be unproductive, early consideration of some of the key more significant unknowns will be advantageous. A short list of these includes the following:

  • Scope for negotiation: Certain parts of the IPC will need to be negotiated, which is principally good. However, the degree to which this is good will depend on the nature of these parts and whether there is scope for genuine commercial negotiation. An efficient tendering environment will be important for getting the most out of negotiations. For example, a requirement for negotiated parts of an IPC to be subject to a further layer of government approval could frustrate the reform process and encourage suspicion during tendering and documentation of the project. However, an IOC with clear and well-defined objectives will likely get the most out of whatever room there is to negotiate with the NIOC, even where the ability to propose deviations is limited to the tender process, before bilateral discussions with a preferred IOC have begun.
  • Local partnerships: By requiring a local partnership, the Cabinet approval makes it clear that arrangements with a local partner will be required prior to the conclusion of the tender process. IOCs may only partner with local companies approved by the NIOC. Although some have already been named, it is unlikely that any final list of approved companies would be a significantly long one. It is also unlikely that the NIOC’s approval criteria will include any consideration of the stance taken by various sanctioning authorities. Each IOC proponent will need to carefully asses the suitability of any local company, not just for sanctions risk, but also for its financial and technical capacities and synergistic appropriateness.
  • The oilfields: The IPC is expected to apply to between 34 and 74 oilfields, with 10 to 15 expected to be included in the first round of IPC tenders. This number includes fields in existing blocks that would not have been commercially practicable to develop under the buyback model. Some of these fields will be better than others – and others may be excluded altogether. In fact, the Government has said that it will prioritise joint development projects with neighbouring NOCs.[1] Although arguably geopolitically correct, this could mean that priority projects are excluded from the pool of IPC-eligible fields or that the first ‘public’ IPC tender round will only occur after bilateral arrangements for these priority projects are sufficiently in place.
  • Tender process and requirements: Not much is known about the tender process design and substantive bidding requirements. Of these, most interest will be on the commercial, legal and technical variables that IOCs can bid and how those variables will be evaluated.

    We know from the Cabinet approval that a tender for IPC category 1 (exploration) will contain a common regime where IOCs will be invited to bid to perform a set of minimum obligations that the NIOC has defined[2]. Predictably, the Cabinet approval also provides the fee payable under the IPC to perform those obligations will be one of the core evaluation criteria. This means that IOCs will need to be capable of influencing the amount of the fee in their tender submissions.

  • Sizing the fee amount: The mechanism that IOCs will use to size the fee is not clear. It may follow Iraq’s ‘Technical Services Contract’ model, where contractors bid the fee element to which the ‘R’ factor will be applied. However, this approach would put additional pressure on the adequacy of the incentive regime, as (for example) more expensive technologies or riskier projects will distort the relationship between costs and production revenues.

    A number of additional or alternative elements could be adjusted by IOCs to appropriately size the fee, but these will make comparing bid submissions more difficult for the NIOC. We expect that the NIOC will prefer a tender design that produces a single ‘comparator’ – one that is easy for pricing (and therefore cost) to be compared across different bids.

  • IP transfer: IP transfer is at the core of the reforms. However, the extent of the commitment for IOCs is unclear. On what terms will an IOC satisfy its obligation to transfer and develop technology? Will this obligation extend beyond local oil and gas companies, and also apply in respect of local subcontractors of the joint operating company? Critically, upon a sanctions ‘snapback’, will IOCs subject to those sanctions be effectively required to abandon its IP or be exposed to significant financial liability for breach?
  • ‘Iranianisation’: Iran expects a transfer of managerial responsibility to Iranian nationals. However, the pace at which executive management roles are to transferred from IOC nominees to local oil and gas companies remains unclear. The potential consequences of local company management making key decisions about, for example, the use and application of an IOC’s technology, could be significant (especially given IOCs are liable for the joint operating company’s actions).
  • Survival of the buyback? Although the buyback contract will effectively be replaced by the IPC, article 12 of the Cabinet approval provides that the NIOC is still authorised to enter into a modified form of buyback contract for identified but undeveloped resources “if necessary” with the prior approval of the Ministry of Oil. The modifications relate to cost recovery and remuneration. The scope of this authorisation is unclear, but it would seem to be intended to facilitate a transition away from the buyback model rather than to preserve the model to be used in the future.