Low oil price - high disputes risk: The scope for disputes in a world of low oil prices

Oil prices have recently reached historic lows. Oil companies are faced with a number of potential legal issues as low oil prices impact their trading and operational agreements. In this briefing we consider some of the key issues triggered by the current low oil price environment.

1. Introduction
2. Negative pricing under oil trading agreements
3. Lack of storage and potential shut-ins – implications on TPAs and TPOSAs
4. Joint Operating Agreements  (JOAs)
5. Has a party complied with the Reasonable and Prudent Operator standard?
6. Low oil price and existing force majeure claims
7. Rig contracts
8. LNG Sale and Purchase Agreements (SPAs)

1. Introduction

Oil prices have collapsed since the start of the year.  In April, Brent reached below $20 a barrel, its lowest level in 18 years (and a fall from $70 a barrel in January), while the US benchmark West Texas International fell to its lowest level in history, reaching negative prices.

Prices have been driven down by concerns around oversupply, compounded by the collapse in demand caused by COVID-19 and the price war between Russia and Saudi Arabia. Whilst prices have recovered a little, they remain low – and some estimates predict oil demand may not return to pre-crisis levels until the end of 2021.¹

Low oil prices will have a wide-ranging impact on an oil company’s contractual arrangements. We have considered the effect on financing arrangements, and specifically the 'material adverse effect' clause, here. Similar considerations may apply to 'material adverse change' clauses in M&A agreements, and construction projects are also likely to be affected.

In this briefing, however, we focus on the implications of these low oil prices on certain key trading and operational agreements for oil companies. These are, in our recent experience, some of the agreements which are coming under particular strain. We consider the position under English law, which is commonly adopted by parties in the oil and gas industry, but the same themes apply under contracts governed by other common law systems.

2. Negative pricing under oil trading agreements

We begin with oil trading agreements. In such agreements, the contract price is often set at a discount to the indexed oil price. With the current low oil prices (including, as noted above, negative WTI prices), we have seen the contractual pricing formula result in negative contract prices. These would, if applied, require the seller to pay the buyer for taking the oil.

This obviously places the seller in an invidious position. If it performs, it is paying to sell its product. If it fails to perform, it is exposed to a claim for breach of contract.

The express terms of the contract may stipulate what happens in this scenario. For example, the contract might set a ‘zero’ floor price, ruling out negative prices. Equally, the contract might expressly allow negative prices. But if the contract is silent on the point (and assuming no force majeure or frustration arguments are available), a Court or arbitral Tribunal applying English law will construe the existing terms to ascertain whether a negative price was ever contemplated by the parties, and/or whether a term should be implied into the contract. 

The Court of Appeal has considered a similar issue in the context of a finance agreement when interest rates turned negative.² The Court made clear that the position will turn on a careful analysis of contract as a whole – and although both sides may argue that the draftsperson could have made the matter clear had he chosen to do so, “it is more important to look carefully at what the drafting did include, rather than what it did not”.³ 

When looking at the drafting, the parties may seek guidance from the payment mechanisms in the trading arrangement: do these only contemplate a payment being made from the buyer to seller, or are the payment provisions two-way? Faced with competing interpretations, the English Courts may fall back on the interpretation which is most consistent with ”business common sense”,⁴ which may favour the seller in this exceptional situation.  Indeed, in extreme situations there may be scope to argue that paying the buyer to receive product reaches a point of commercial absurdity which could not have been intended by the parties.⁵

3. Lack of storage and potential shut-ins – implications on TPAs and TPOSAs

The lack of demand for oil globally is causing oil storage to fill and tanker capacity is increasingly limited, both for storage and export. If there is no demand and no storage, then shut-ins or reduced production are likely, or even inevitable. Norway, for example, recently announced that it will be cutting oil production from June 2020 to December 2020 and the existing cuts by the OPEC+ countries have been well-publicised.⁶

Shut-ins or reduced production clearly give rise to technical issues, and may well involve the regulator if approval is required. They may also give rise to competition concerns if they are co-ordinated between different fields owned by different companies. Those issues are beyond the scope of this briefing. However, it is also clear that shut-ins or reduced production will impact on a producer’s contractual arrangements. 

a. TPAs

The producer of an offshore field in the UKCS is highly likely to have reserved capacity in an offshore pipeline under a Transportation and Processing Agreement (TPA). The TPA will typically contain 'send or pay' obligations. A producer will only be relieved of its send or pay obligations in limited circumstances. One of these circumstances will be force majeure. In a shut-in or reduced production scenario, that quickly leads to an analysis of the reasons for the shut-in or reduced production.  

The transporter might call force majeure if they are unable physically to store oil within the facilities, in turn requiring a producer to reduce production or shut-in. Recent reports emphasise that the UK’s system has very limited or no offshore storage, while the onshore storage is designed for continuous uptake: for example, the Forties pipeline, which carries 30% of the UK’s oil, has storage capacity equal to just seven days of production.⁷

However, difficulties potentially arise if the producer is seeking relief from its send or pay obligations by relying on the fact low oil prices have made production uneconomic, thereby causing a shut-in or reduced production.

It will be challenging to argue that low oil prices alone amount to a force majeure event. In a 2005 case in the English High Court, a buyer of gas claiming force majeure tried to rely on the fact that the gas prices were so high that the buyer could only perform the contract at a degree of loss that was  beyond anything contemplated at the time of the agreement.⁸ The English High Court held that was not a force majeure event because it did not prevent performance. The judge said that:

“the fact that a contract has become expensive to perform, even dramatically more expensive, is not a ground to relieve a party on the grounds of force majeure.”⁹

b. TPOSAs

If the field shutting-in or reducing production is a hub platform, the producer will also need to consider its obligations under any Transportation, Processing and Operating Services Agreements (TPOSAs).

Under the terms of the TPOSA, a hub owner will have committed to receive, process and transport properly nominated volumes of fluids and gas from satellite platforms. Again, a producer will only be relieved of those obligations in limited circumstances, including force majeure. 

Given the satellite field is entirely dependent on the hub platform, if the hub shuts-in or reduces its production and fails to make out force majeure, it may be exposed to a potential damages claim from the owners of the satellite field arising from breach of the obligations in the TPOSAs.

4. Joint Operating Agreements  (JOAs)

A decision to shut-in or reduce production, although made by the operator, is likely to require approval under a JOA. JOA disputes are more likely to arise in a low oil price environment. In particular, as cashflows become straitened, parties under JOAs may seek to protect their positions. If counterparties are showing signs of financial distress, and in particular if cash calls go unpaid, parties should be prepared to assess the default notification requirements, cure periods, changes to voting rights or even the acquisition of the defaulting party’s participation through options to purchase or forfeiture. 

Whilst the JOA may grant ostensibly clear and unequivocal express rights to the non-defaulting parties in relation to the defaulting party’s interests, in practice there may be additional legal or other local formalities to take in to account – for example, state approval of any transfer of interest or mandatory pre-emption rights.  It also bears emphasis that production entitlement, which normally in an event of default is allocated to the non-defaulting party, may seem less attractive in the current environment given the shortages of storage capacity and the rising costs of storing oil.

In formal insolvency situations, care should be taken to comply with statutory insolvency regimes in dealing with or taking possession of the distressed party’s assets. Parties should also be aware that insolvency may be a ground for a regulatory authority to revoke licences granted to both JOA parties, even if only one party is in financial distress.

5. Has a party complied with the Reasonable and Prudent Operator standard?

One thread running through all the contracts referred to in the previous sections is the 'Reasonable and Prudent Operator' (RPO) standard. 

The standard may be relevant in a number of ways. Before claiming force majeure, the event may need to be beyond the control of a party acting as an RPO. Or once a force majeure event has occurred, the party may need to take mitigation steps acting as an RPO. An operator may be exposed to liability under a JOA if it does not act as an RPO. More broadly, a party may agree to perform all 

obligations in a contract to the standard of an RPO. Any decision to shut-in or reduce production may therefore be viewed against the standard of an RPO. 

The RPO standard is typically defined in the contract and the common contractual definitions we have seen often have similar, if not identical, elements. The common form of the RPO standard has been construed by the English Courts:

• The RPO standard is objective, although a Court considering how a party is required to act will objectively consider how an RPO facing the same position and circumstances would act.¹⁰ This may involve expert evidence to assist the Court.
• To be an RPO, a party actually has to try to perform its contractual obligations. A party not seeking to perform at all does not fall within its scope.¹¹
• An RPO is entitled to take into account its own commercial interests, but it would also consider the adverse financial consequences for its contractual counterparty of taking a certain action.¹²
• An RPO would have regard to industry practice.¹³

In a low oil price environment, including shut-in decisions, the obligation to perform the contractual obligations, as well as the tension between an RPO’s commercial interests and its counterparty’s commercial interests, are likely to be particularly tested.

6. Low oil price and existing force majeure claims

Much has been written about relying on COVID-19 as a force majeure event – and that is not the focus of this briefing. However, the low oil price does give rise to a further complication for existing or future force majeure claims under operational contracts in which the event relied on is COVID-19. 

The causal link that must be shown between the force majeure event and the failure to perform will depend on the construction of the force majeure clause. However, the analysis may require a party to show that the force majeure event is the sole effective cause of the failure to perform.¹⁴ This was the interpretation recently given by the English High Court to a force majeure clause in a drilling rig contract. Thus, where two events occurred to prevent an oil company from fulfilling its obligations under the contract, but only one of them was a force majeure event, the company could not claim force majeure because the sole effective cause of its failure to perform was not a force majeure event.¹⁵

Depending on the wording of the clause, a Court may also apply a ‘but for’ analysis: ‘but for’ the force majeure, would performance have been prevented? Under this analysis, if performance would have been prevented in any event, force majeure relief will not be available. So a shipper of iron ore pellets from Brazil to Malaysia trying to claim force majeure could not rely on a dam burst which made it impossible for it to perform, because on the facts of the case it would have defaulted in any event.¹⁶

Against this background, the concurrent drop in oil price and the COVID-19 pandemic potentially complicates relying on COVID-19 as a force majeure event. If parties have already issued a notice, or are considering whether to rely on the pandemic as a force majeure event, but the low oil price results in a party defaulting in any event (for example due to a decision to shut-in or reduce production), it may be difficult to say that COVID-19 is the sole effective cause of the inability to perform. Similarly, if the clause requires the party claiming force majeure to satisfy the ‘but for’ test, and 'but for' COVID-19 the contract still would not have been performed, force majeure is unlikely to be available.

7. Rig contracts

Rig contracts have historically given rise to disputes in a low oil price environment. Such contracts will typically have a ‘termination for convenience’ clause, allowing the rig hirer to terminate for a fee.¹⁷ This fee is likely to be derived from the rig standby rate multiplied by the remaining days of the term (if the term has started), or a specified number of days (if the term has not yet started). Alternatively, parties may prefer to place the rig on standby and pay the standby rates, thereby avoiding the spread costs associated with drilling (such as additional support vessels or fuel).

Of course, if a party has a valid right to terminate the contract (for example for cause, or relying on force majeure) it could elect to exercise those rights and bring the contract to an end. English Courts and tribunals applying English law have frequently taken an interest in the potential motivations of hirers seeking to terminate or call force majeure, particularly in a low oil price environment, and irrespective of whether such questions of motivation are relevant on a strict legal analysis. Parties taking this course should take care to document the breaches on which they rely for termination or the precise effect of the force majeure event on their performance of the contract.

8. LNG Sale and Purchase Agreements (SPAs)

The last set of contracts we will consider are LNG SPAs.

1. Force Majeure issues

Although we touched on the storage issues with oil above, a lack of storage causes considerably more difficulty in contracts for LNG than contracts for oil. The lack of demand for energy and economic contraction, which underpin the recent falls in oil prices, have also impacted the price of LNG. However, there are particular features of LNG as an energy commodity which further complicate the picture.

For one thing, the LNG market is less liquid than the oil market and LNG is technically far more difficult to store for long periods of time. In addition, LNG is often sold under long term ex ship 'take or pay' contracts, with specific destination clauses and limited diversion rights. Whilst the spot market for cargoes of LNG has grown significantly in recent years, it does not begin to resemble the market for oil.  

The combination of these factors means a lack of LNG storage capacity at the intended destination can quickly make the contract impossible to perform, because LNG cannot be unloaded. In those circumstances, a buyer’s remedy is likely to lie in force majeure, and buyers in Asian markets have claimed force majeure under long-term LNG SPAs.¹⁸ 

It is trite but true to say that each force majeure claim turns on the wording of the contract. However, in broad terms a buyer in this situation will need to prove causation and mitigation. 

In relation to causation, the buyer will need to identify the force majeure event which has actually caused the buyer’s non-performance. If 'pandemic' is listed as a force majeure event in the contract, this may be alighted on by a buyer. But the buyer may then need to establish the links in the chain of causation between the pandemic and the lack of storage capacity. Relatedly, the buyer may need to isolate the specific role of COVID-19 as a cause of full storage tanks, against a global reduction in demand for LNG which may be complex and multi-faceted.

The other important issue relates to mitigation. A buyer claiming force majeure will likely be obliged to mitigate, whether as an express contractual obligation or as a matter of law. An important question from a mitigation perspective, in our view, will be to what extent, if at all, a buyer faced with storage difficulties is required to divert cargos to sell on the spot market if can contractually do so, even where it would be uneconomic for a buyer to do so. This question cannot be answered easily. It will turn on a careful review of the underlying factual position and an analysis of the standard that must be met when mitigating (typically either an RPO standard or a reasonable endeavours obligation). 

b. Price reviews

Price reviews are another other way in which LNG SPAs (and many long-term GSAs) are likely to be affected by the low oil price. The contract price in many such agreements is linked to oil or oil product prices (i.e. Brent or Japan Crude Cocktail (JCC), typically on a 3 or 6 month average). It will therefore take a little while before the low oil prices materialise in changes to the contact price.

Over the last few years, we have seen oversupply of LNG as more projects commenced production in Australia and the US, and Asian demand decreased (even before the outbreak of COVID-19). This has led to low LNG spot prices, whilst oil prices stayed comparatively high – leading to buyers (on the whole) initiating price reviews under Brent or JCC-linked SPAs.

On one view, a low oil price may lower the differential between contract prices and spot prices, and therefore decrease the need for price review – although spot prices for LNG are reaching historic lows, so the differential may remain.

In any event, it will take some time to assess the extent to which the low oil price environment is a short-lived phenomenon, or whether it instead heralds a longer-term, structural change. Nevertheless, oil price shocks have triggered price review requests in the past and it seems highly likely that COVID-19 and the current low oil price environment will do so again.