Risk management in international oil and gas contracts managed in the United Kingdom Continental Shelf

July 2010

“The ability to deal with people is as purchasable a commodity as sugar or coffee, and I pay more for that ability than any other under the sun.” ¹

 

Introduction

The petroleum industry is a multibillion-dollar business which has inherent risks at every stage of production. This risk is all too real. Tragic disasters like Flixborough, Piper Alpha, Sleipner Alpha, Texaco Refinery Milford Haven, Pembroke Refinery and Conoco Humber Refinery culminated with the loss of life, property and resources. 

Most recently, a Bond helicopter crashed into the sea north-east of Scotland some 35 miles off the Aberdeenshire coast killing at least 8 men on 2 April 2009. After these serious incidents and others worldwide which claimed countless lives, the UK government saw fit to pass health and safety legislation thereby removing this aspect from the hands of the parties when negotiating any oil and gas development within the UK. ²

Petroleum production peaked in the United Kingdom Continental Shelf (UKCS) in 1999 and has been declining steadily at an average rate of 6.86% per year. The UK was an exporter of petroleum but in 2004 become an importer of gas. Reliance on imported energy is a risk, whether from uncertainty of an outcome or the uncertainty of various combinations of outcomes. This uncertainty was very real in January 2008 with the dispute between Russia and the Ukraine.

Risks are managed in different ways all around the world, but predominantly the most effective way, from a legal point, is via contract. The main objective of any petroleum operation is to secure maximum efficiency at exploration, development and production whilst hopefully achieving maximum profit. To attain maximum profits, one would identify and quantify the risks, which is difficult especially when most risks are unknown and if known, are uncertain. 

The Monte Carlo simulation ⁴ might be one way to determine acceptable levels of risk but determining a company’s Beta coefficient ⁵ is also another. In upstream operations parties are not prepared to rely on mathematical formulas or theories when millions of dollars are at stake to fund a project. 

History

Contracts for exploration and exploitation of energy have taken various forms over the years. Initially, countries offered concessions to investors, ⁶ usually international oil companies (IOC’s), where investment would be made by the IOC in return for a large area and long periods of time. The state ⁷ would be paid a royalty, usually a very small percentage with little state involvement or supervision. This was the typical arrangement in the Middle East, South America, Africa and parts of Asia. In the 1950’s this was interpreted to be a threat to national security and thus saw the genesis of “permanent sovereignty” exercised by the Host Government (HG) over its natural resources. ⁸

Consequently, a new generation of contracts evolved: joint venture agreement (JVA); production sharing agreement (PSA); joint operating agreement (JOA); service and ancillary contracts which gave substantially more control to the HG and the activities of the investor. Contracts have added protection if the investment is within a member of the Energy Charter Treaty (ECT). The investment provisions of the Charter should be embedded in these contracts which cannot be circumvented. ⁹

Investors signed to a JVA accepted all the risks of exploration, and only if commercial production was reached would costs be shared with the HG. The investor has no title or ownership over any of the installations, equipment or other assets located in the HG. They are all owned by the national oil companies (NOC’s). Investors usually retain a percentage of the sales at commercial production. In a short period of time, risk was shifted from the HG back to the investor. The concession system were good times for IOC’s. ¹⁰

In comparison, under a PSA the HG grants the investor exclusive exploration and production rights, without transferring mineral rights, for a period of time. The difference is that under a PSA the investor can recoup its costs in full and is entitled to a share of profit oil as dictated in the PSA. This is the preferred investment contract as it gives the investor exclusivity to explore and produce without the heavy-handed control of the HG that owns the reserves. ¹¹

Iran’s buyback contracts are still draconian compared to the standard industry PSA. Under the buy-back system, initially for a period of 5 - 7 years, the National Iranian Oil Company (NIOC) and the investor agree to a full development or re-development plan for the subject field for a lump sum. The investor is required to implement the development plan and upon completion the field is “given back” to the NIOC. The investor is paid for the costs of development and its fee in oil from production of the field. 

A recent change has seen the increase of the buy-back period to 25 years to attract investors. This is primarily the main reason why Iran’s petroleum industry is lacking investment. U.S and UN economic sanctions are another significant reason. Although the buy-back regime is heavily criticised, it’s understandable why IOC’s are rushing to sign up. ¹²

Risk mechanisms and contract provisions

The risks in offshore drilling are significantly increased due to working at various depths in water. The main risk categories are geologic; environmental; completing the project; market risks; and political risks each with their weight dependent on the available information of engineering data and knowledge of the economy. These variants allow the parties to deal with risk in a number of ways. Typically, a party may refuse to operate or proceed with the project. More often than not, risk is reflected in the rate of return or the price base for entering into a deal. Sometimes risk may be assigned, spread or excluded but these methods are usually under sophisticated terms and conditions within a contract.

Risk is a matter of perception and through the use of contractual mechanisms parties may exclude or financially limit an event. These contracts include clauses limiting risk between the parties, such as: confidentiality; limitations of liability; defects liability; transit liability; supply liability; force majeure; renegotiation; warranties; safety provision; political; “grandfather” clauses; hardship clause; adverse effect clause; dispute resolution clause; stabilisation clause; insurance; indemnity and exculpatory clauses in negligence or compliance with regulatory provisions. 

A “grandfather” clause is an exemption or exception that allows an old rule to continue to apply to some existing situations, when a new rule will apply to all future situations. For example, a "grandfathered power plant" might be exempt from new, more restrictive pollution laws. Often, such a provision is used as a compromise, to effect new rules without upsetting a well-established logistical or political situation not being retroactively applied.

Without insurance foreign investment would be non-existent, or at the very least minimal. These insurance policies are sometimes referred to as political risk insurance where investors have a remedy directly through the policy without having to sue under the original investment agreement or bilateral investment treaties. 

Political risk insurance is offered by Multilateral Investment Guarantee Agency (MIGA), the Overseas Private Investment Corporation (OPIC) which is owned by the US government. OPIC has developed specific coverage for its national petroleum industry that involves overseas in foreign investment. Insurance for contractually related risks (default, insolvency or financial instability, or repudiation) are generally available by private underwriters (such as Chubb and Lumley) which varies in cost and coverage in each country. ¹³

1. Acts of violence, war and aggression are covered by political risk insurance. These aren’t the only areas that political risk insurance covers. They also include: ¹⁴
2. confiscate, expropriate and nationalise (CEN) by a HG without fair compensation; 
3. Intervention by denial or cancellation of licenses and permits by the HG which deprives the use of property; 
4. Terrorism, sabotage and kidnappings; 
5. FOREX – foreign exchange risk where earnings cannot be converted or repatriation is blocked; 
6. Breach of contract either by a HG or a state-owned company usually for default in payments for deliveries; 
7. Frustration due to events, usually political, by the HG; 
8. Taxes are increased to levels that make it impossible to function in business; 
9. Wrongful demands made where there has been no default or breach but the HG calls and draws on arranged sureties such as letters of credit, bonds or guarantees; 
10. Regulations passed to restrict production to a level where it’s impossible to economically operate; 
11. Environmental restrictions and regulations are revised and imposed retroactively by the HG knowing full well that they cannot be complied with; 
12. Economic sanctions, blacklisting and prohibiting trade; 
13. Arbitral awards not adhered to by the HG, usually failing or defaulting on payment under the award.

At times governments have been known to CEN. An example of unilaterally altering terms of oil concessions is the Venezuelan government against ExxonMobil with expulsion form the Orinoco belt. 

Petroleum contracts usually include indemnities where one party will agree to hold the other harmless for all costs, losses or damages that arise from an event, irrespective of the issues about negligence, contract breach or breaches of statutory obligations. 

Contract trends on the UKCS

Bargaining power in upstream transactions is as vital to the deal as oxygen is to humans. With the collapse of the oil price in 1986 and oil remaining cheap until 2002, upstream operations were adversely affected worldwide. Spending hundreds of millions of dollars on an offshore project was unwise when profitability was in question. In this period, and as a direct consequence of limited returns on big projects, petroleum industry companies either merged or were taken over.

The British National Oil Company (BNOC) was formed in 1975 and had a 51% share in every UKCS licence as of statutory right. BNOC developed its own JOA and it became almost universal on the UKCS but favoured non-operators. BNOC was transferred to Britoil Plc in August 1982 ¹⁵ and in 1988, on instructions from the Thatcher government, Britoil Plc was dismantled and sold to BP. ¹⁶

The DTI was formed in 1970 with the merger of the Board of Trade and the Ministry of Technology which created a new cabinet post of Secretary of State for Trade and Industry. The DTI was disbanded on 28 June 2007 making way for the Department of Business Enterprise and Regulatory Reform (BERR). BERR and the Department for Environment, Food & Rural Affairs (DEFRA) merged in October 2008 and is now the Department of Energy and Climate Change (DECC).

Contracts were always tendered out for significant works. The low oil price had an effect on the way contracts were negotiated. The operator offered financial incentives with rewards for exceeding an agreed benchmark and penalties for failing to meet the mark. Contractors favoured financial incentives and resisted any penalties.

The UKCS Licensing Regime has associated risks with its issue. Under the UKCS Offshore current Model Clauses include: the need for government approval of significant operations; ¹⁷ the power to impose exploration programs and to execute works to that programme; ¹⁸ if the licensee breached any term of the Licence then forfeiture of the entire Licence without any compensation or refund would follow.¹⁹

If there are joint licensees and only one of the licensees is in default, the government also has the power to forfeit the entire licence.²⁰ It is a draconian law but one that is still used. In 2004 two small oil companies forfeited their Licence without compensation due to their failure to carry out the agreed abandonment programme. As a result the DECC takes a much closer look into the financial positions of smaller companies applying for licences on the UKCS. The government also has the power to unilaterally vary the terms under Licence, which was practiced in the early days of exploration and production in the North Sea. These days the UK government has been quite disciplined not wanting to discourage any legitimate investment.

Further, the government can unilaterally change the tax rate or impose new taxes. For example, the abolition of royalty payments for all new fields in 1982 and the abolition of Petroleum Revenue Tax for fields developed after 1993. However, in 2003 Gordon Brown, Chancellor of the Exchequer, increased corporate tax for oil and gas producers with a special 10% levy due to high oil prices. This was done again in 2005 when it was apparent that the budget was in deficit, and imposed an additional 10% levy to close the gap. As a consequence, the corporate tax rate for companies producing oil and gas on the UKCS is 50%. 

The contract suite originated from the United States (US) in some form or another. In the UK, the last 12 years has seen a change in traditional contract patterns on the UKCS, not due to the rise in oil prices but because of the decline of reserves and subsequent production. The oil Majors withdrew from the region selling their interests to substantially smaller operators who have become quite entrepreneurial. These operators function without large in-house drilling or contracts departments so they contract on a “turnkey” basis. This requires the contractor to manage the whole operation including all subcontracts in return for a percentage of total project expenditure.

Thorpe, whilst acting for a small operator, witnessed one of the most aggressive commercial behaviour ever within the industry. The story is as follows: 

“I was acting for one of the small operators which was drilling an appraisal well. There was a contingent plan to “frack” the well if the results justified it. For the uninitiated, fracking involves using a specialised vessel or “frack boat” to pressure the well until the casing at the bottom splits. This would enable production from the well to begin immediately, and so avoid the need to drill a separate development well, bringing production of the field forward by 18 months and greatly improving the economics of the development. 

The operator was in discussions with the owners of two frack boats available in the North Sea, but had no contract with either of them. The well results were encouraging, so the operator went out to contract a frack boat, but one of them was busy in the Norwegian sector. 

The owner of the only available vessel not only demanded top dollar for use of the boat, but also produced a non-negotiable “farm–in agreement” which it required to be signed before it would mobilise the vessel. The farm-in agreement gave the contractor the option after completion of the well to take 12.5% equity stake in the project, without payment and without bearing any part of the well costs.” ²¹

Initially, the industry lacked any standard set of forms that would be balanced amongst parties. Contracts favoured one party or after lengthy negotiations and considerable cost, were incredibly difficult to read and interpret. In 1992 the Department of Trade & Industry (DTI) attempted with limited success to harmonise contractual relations between operators and contractors with the aim of reducing costs via the Cost Reduction Initiative in a New Era (CRINE). 

In 1999 the UK government sought to make the supply contracts on the UKCS more efficient and introduced the Leading Oil and Gas Industry Competitiveness (LOGIC) standard contracts. LOGIC initiative was the successor to CRINE and the contracts under LOGIC are far more balanced. However, the collapse of oil prices has seen a rise, in use of CRINE standard forms by operators as bargaining power and leverage shifts so too does the resurgence of CRINE standard forms. 

CRINE is no longer operational and LOGIC has taken over all its former responsibilities. These contracts balanced the rights of the operator and contractor, a far call from years earlier. Then in 2002 oil prices surged and demand for oil grew with the rise of China and India entering the modern world. This led to an increase in demand for contractors which tipped the balance of bargaining power strongly in their favour. ²²

Until recently, this was the universal position. The surge in demand has created a contractor shortfall which means they can name their price and better still impose their terms flexing their newfound power. Oil prices collapsed after last summer’s record of US$147 per barrel in July 2008. CRINE contracts favoured the operator when oil prices were low. The balance of power seems to be shifting back to operators. 

The high oil prices of 1980 led to a record level of drilling in the UKCS with a huge demand for rigs. Tendering was non-existent and oil companies searched the globe and were literally at the mercy of contractors who inflated prices, for example of semi-submersibles by $100,000 per day. Once the oil price collapsed in 1986 the position reversed overnight with charters falling to $10,000 per day. 

After rising steadily over the past 5 years, the start of 2008 saw oil power through US$100.00 a barrel and continue to US$147.00 by the second week of July 2008. In the second half of 2008 to late December 2008 the oil price collapsed to US$35.00 a barrel. It is currently hovering around US$50.00 per barrel.

UK oil and gas cases 

Previous legal actions arising from accidents in the past should be considered for guidance to prevent similar risks developing in future operations. Following the destruction of the World Trade Centre in September 2001 and the Petrobas P-36 40 storey oil platform in March 2001, at the time the world’s largest offshore rig worth US$480 million, which sank after two explosions killed at least 11 people, insurance premiums substantially increased requiring parties to rethink the allocation of risks within their contract provisions. 

The indemnity provision is one of the most important contractual clause and is, if used correctly, the ultimate risk management tool. The purpose of an indemnity clause is to transfer and allocate liability for certain events or risks between the parties thereby avoiding expensive and time-consuming litigation. When responsibility has been allotted each party insures against its risk.²³

An “indemnity” is a contract between two parties in which one agrees to be liable for loss or damage sustained by the other and/or a third party from a specified act or condition or damage which results from a claim or demand. Indemnity provisions come in different forms and are known by other names such as: survival provisions; release; exculpation; disclaimer; “hold harmless” and “as is” clauses. ²⁴ In the UK the common law position of indemnity only allows for the recovery of damages to the indemnitor in instances where there is no participatory fault on the part of the indemnitee.²⁵

Seller LJ confirmed the English position of indemnities in Walters v Whessoe Ltd and Shell Refining Co. Ltd: ²⁶

“It is well established that indemnity will not lie in respect of loss due to a person’s own negligence or that of his servants unless adequate and clear words are used or unless the indemnity could have no reasonable meaning or application unless so applied…”

Devlin LJ,²⁷ analysing the construction of indemnity clauses, equally concurred:

“It is well established that if a person obtains an indemnity against the consequences of certain acts, the indemnity is not to be construed so as to include consequences of his own negligence unless those consequences are covered either expressly or by necessary implication. They are covered by necessary implication if there is no other subject matter upon which the indemnity could operate. Like most rules of construction, this one depends upon the presumed intention of the parties. It is thought to be unlikely that one man would agree to indemnify another man for the consequences of that other’s own negligence that he is presumed not to intend to do unless it is done by express words or by necessary implications.”

It is only through the use of indemnity provisions that the common law is altered, even if a party is at fault or negligent. However, the English courts are hesitant to accept this no-fault indemnity and have devised tests to satisfy themselves that this is the intent of the parties and what they bargained. The courts will consider the agreement and insist that any indemnity is clearly stated and unequivocal. 

Lord Morton of Henryton devised a three-part test in relation to indemnity clauses in the Privy Council case of Canada Steamship Lines Ltd v R: ²⁸

 “(1) If the clause contains language which expressly exempts the person in whose favour it is made (hereafter called “the proferens”) from the consequence of the negligence of his own servants, effect must be given to that provision…

(2) If there is no express reference to negligence, a court must consider whether the words used are wide enough, in their ordinary meaning, to cover negligence of the part of the servants of the proferens…

(3) If the words used are wide enough for the above purpose, the court must then consider whether “the head of damage may be based on some ground other than that of negligence,” to quote Lord Greene the “other ground” must not be so fanciful or remote that the proferens cannot be supposed to have desired protection against it; but subject to this qualification, which is no doubt to be implied from Lord Greene’s words, the existence of a possible head of damage other than that of negligence is fatal to the proferens even if the words used are prima facie wide enough to cover negligence on the part of his servants.”

This brings us to the Piper Alpha disaster, litigated in EE Caledonia Ltd v Orbit Valve Co. ³⁰ The plaintiffs, EE Caledonia Ltd (EEC), were operators and occupiers of the Piper Alpha drilling platform in the North Sea and the defendants, Orbit Valve Co (OV), were an engineering firm, contracted by EEC to provide a service engineer to overhaul the valves. A series of explosions and fire destroyed the platform killing 165 people, including the defendant’s service engineer. The plaintiff settled the claims of the deceased estates on the basis that death was caused by the negligence of the plaintiff’s servants and breaches of statutory duty. The actual cause of the disaster was as a result of the negligence of the plaintiff’s lead operator.

Within the agreement, each party agreed to indemnify the other against “any claim… or liability… arising by reason of… death of any employee… of the indemnifying party, resulting from or… connected with the performance of this order.”  

The plaintiff looked to the defendant for indemnity under the contract but it was dismissed at first instance. The Court of Appeal, Steyn LJ held that after following the reasoning of Walters and the three part test in Canada Steamship Lines the plaintiff could not rely on the indemnity provision because it did not refer to negligence but although it was wide enough to cover negligence, the plaintiff failed due to the existence of the “other ground” – i.e. other heads of on which liability could be based; namely, breach of statutory duty. 

On a similar issue but more related to insurance subrogation, the case of National Oilwell (UK) Ltd v Davey Offshore Ltd ³¹ deserves a mention. This concerned the supply of a subsea well head completion system which formed part of a floating oil production facility.  Under the sub-contract between Davy Offshore (DO) and National Oilwell (NOW), DO agreed to effect insurance for NOW’s goods up until delivery of the system, and provided that NOW would be liable for £10,000 every incident that occurred before delivery. The policy covered DO until the end of the project, and the loss took place after delivery but before the end of the project.

The policy of insurance stated that “other assureds” were covered, “unless specific contract(s) contain provisions to the contrary in which event, insurance hereunder for such specific contract(s) only, shall be limited accordingly.”  The policy also included an express “waiver of subrogation” clause.

Coleman J held that NOW were outside the scope of the cover and could not rely on the subrogation waiver, so insurers could recover against NOW. Not only is the wording of the policy relevant, but also the wording of any other contracts between the principal assured and the relevant contractors, in order to determine whether it is possible to subrogate against a contractor who believes he is a co-assured.  

CRINE and LOGIC standard forms

The UKCS has the most sophisticated contractual terms of all the petroleum regimes in the world. These standard forms contain provisions that deal exclusively with the allocation and management of risk. The main clauses dealing with risk allocation and liability which are repeated through the suite are: indemnities; suspension; terms of payment; insurance; consequential loss; default provisions; defects correction; liquidated damages; limitation of liability; Contracts (Rights of Third Parties) Act; termination; and dispute resolution.

These agreements include “boilerplate” provisions that are generally found towards the end commonly bundled together. These are usually non contentious but liability and indemnity clauses are contained within the boilerplate. ³²

Due to issues of interpretation of indemnity clauses, initially by the parties but more importantly by the courts as seen above, a new form of indemnity clause was created by LOGIC in 1999; the Mutual Hold Harmless Indemnity (MHHI) or as sometimes referred to as the Industry Mutual Hold Harmless (IMHH). The IMHH Scheme evolved so as to clarify the “allocation of liabilities and consequent avoidance of overlapping insurance of identical risks”. This Scheme is intended to apply to all offshore works on the UKCS which is among contractors only but is supported by operator groups. The Scheme is owned and administered by LOGIC. 

Either way, it means that mutual indemnities are given by the operator to the contractor and vice-versa. Illustrating by example, the operator will indemnify the contractor against injury, death, or illness of the operator’s employees and against property damage caused by the contractor including conduct amounting to wilful misconduct ³³ or negligence. The same indemnity is afforded to the operator in return.

“Wilful misconduct” has not been defined by the LOGIC suite, however, the Joint Operating Agreement (JOA) for the UKCS produced by the UK Offshore Operators Association (UKOOA) provide the following definition: 

“an intentional or reckless disregard by Senior Managerial Personnel of Good Oilfield Practice or any of the terms of this Agreement in utter disregard of avoidable and harmful consequences but shall not include any act, omission, error of judgement or mistake made in the exercise in good faith of any function, authority or discretion vested in or exercisable by such Senior Managerial Personnel and which in the exercise of such good faith is justifiable by special circumstances, including safeguarding of life, property or the environment and other emergencies.” 

If company A and company B enter into a contract containing such an indemnity and B’s employee is injured then B is responsible for the economic cost of the claim. If B’s employee sues A for the injury and is awarded damages against A, then A could require B to reimburse A for the money paid to B’s employee (based on the assumption that A was at fault).

The indemnity also extends to damages or losses to equipment and material supplied. It is normal for third party indemnities to be provided by the operator but these are limited to drilling operations and not for manufacture and construction contracts. Certain risks are excluded concerning loss or damage to property or consequential loss arising out of: 

1. the carriage of goods by sea;
2. the provision of emergency response and rescue vessel(s) or services associated with them;
3. heavy lift vessel(s); and
4. any activities involving transport by air. 

 

For example, the IMHH Scheme, unfortunately, would not apply to the recent Bond helicopter crash but the Scheme operates where there is no other contractual arrangement between participants.

Sometimes this hold harmless indemnity creates problems for parties as consequential losses might be suffered by other parties. Insuring unquantifiable losses are almost impossible so parties agree to define what “consequential losses” are not covered by the exclusion in the contract. The problem under some LOGIC contracts is that consequential loss is defined to include: “consequential or indirect loss under English law.” What then is “consequential and indirect loss under English law”?

The leading English case on this issue is Hadley v Baxendale. ³⁴ The plaintiffs were owners of a mill and they contracted with the defendant to carry a broken crankshaft to the makers at Greenwich. There was a delay in transit resulting in the mill remaining idle. The plaintiff’s claimed loss of profit. Baron Alderson developed the two limbs to this question:

“Where two parties have made a contract, which one of them has broken, the damages which the other party ought to receive in respect of such breach of contract should be such as may 

(1) fairly and reasonably be considered either arising naturally, i.e., according to the usual course of things, from such breach of contract itself, or 

(2) such as may reasonably be supposed to have been in the contemplation of both parties, at the time they made the contract, as the probable result of breach of it.” ³⁵

 This was accepted in Investors Compensation Scheme Ltd v West Bromich Building Society (No. 1) ³⁶ where the test for direct loss as opposed to consequential loss is what a reasonable businessman would understand from the contract.

 In Victoria Laundry v Newman, ³⁷ the plaintiff ordered a new boiler from the defendant for the purpose of taking on new work of an exceptionally profitable nature. The boiler was not delivered and the work was lost. It was held that, using the second limb, the plaintiff could only recover normal profit since the defendant at the time of the contract had no actual knowledge of the new work.

In British Sugar plc v NEI Power Projects Ltd ³⁸ a contract for the design, supply delivery, testing and commissioning of electrical equipment at a final price of ₤106,585.00 was agreed by the parties. The buyer claimed that the equipment was poorly designed and installed inappropriately which caused the power supply to break down. Damages of over ₤5 million were claimed which represented an increase in production cost and the loss of profits from the breakdowns. The following clause was negotiated over a long period before it was agreed and provided that:

“The Seller will be liable for any loss, damage, cost or expense incurred by the Purchaser arising from the supply by the Seller of any such faulty goods or materials or any goods or materials not being suitably fit for the purposes for which they are required save that the Seller’s liability for any consequential loss is limited to the value of the contract.”

The Court of Appeal held that “consequential loss” and “indirect and consequential loss” refer to damages under the second limb of Hadley. Any direct losses fell into the first limb. Upon strict interpretation of the clause the parties had agreed to limit damages not flowing naturally and directly from the breach to the value of the contract.

In BHP Petroleum Ltd v British Steel plc, ³⁹ special knowledge by the parties are required to be able to claim damages under the second limb of Hadley. The party intending to exclude categories of foreseeable loss would be advised to specify what is included rather than what is excluded; for example, loss of profit, overheads, additional costs required to bring the project back to the level contracted for, loss of revenue. In the UKOOA JOA clause 1.1 provides a definition for “Consequential Loss” which lists what it shall be deemed to include, thereby limiting damages under the second limb of Hadley. 

Under IMHH the operator and contractor accept the risk of their own consequential losses. To illustrate, if an incident occurs and shuts down production who pays for the consequences? The operator takes responsibility for the well and reservoir. The rig operator might also seek indemnity from the operator in regard to its rig and mooring equipment whilst being liable for any pollution to the environment. The operator covers reservoir pollution. Consequential losses are indemnified by the parties to the contract where no claims can be made. 

The total loss claims would be commercially unviable and securing a contractor would be almost impossible. However, that’s not to say that if the contractor delays the project it is immune from any economic penalty. Liquidated damages (LD’s) are still available and are always included. 

LD’s are not uncommon in LOGIC and amounts may increase as time continues beyond the delivery date. Notwithstanding, the amount set as LD’s must be a genuine estimate of loss which might be suffered by the operator as a result of the contractor’s failure to deliver on time. Any amount other than a true loss will be ruled a penalty and be unenforceable. 

A variety of events can give rise to the termination of the contract by the operator. ⁴⁰ Specified grounds include convenience of the operator; suspension; default; defects; force majeure (a detailed definition of force majeure is given in LOGIC contracts); non-compliance with applicable laws, policies and procedures; and insolvency. Termination fees are not unusual and these can be negotiated at the time of the contract. 

Suspension of work clauses are included mainly for health and safety reasons but are known to be used for the “convenience of the company”. This is a very broad power that may be used adversely against any contractor. Although the operator has to give notice of an impending suspension, it does little to quell a contractor’s fears.

Default provisions are always within the boiler plate. The usual events that give rise to defaults (insolvency; receivership; bankruptcy; unlawful assignment; failing to complete the work agreed under the contract) provide an avenue for the non-defaulting party to require the defaulting party to remedy such default within a reasonable time, usually stated within the contract. If the default is not remedied within this time, it gives the non-defaulting party the right to terminate. Upon termination the operator, in most cases, will be entitled to finish the works without incurring any further liability to the defaulting contractor.

If defects arise as a consequence of the contractor’s work, then the contract may require the contractor remedying the defects within a short period and failure to do so will allow the operator to engage another contractor to reperform the work. Should this occur provisions usually allow for set off or recovery from the contractor for this additional cost.

Insurance is usually negotiated between the parties. The question of insurance is never disputed, but what is queried is which party obtains cover for a particular risk. The usual policies which are mandatory by law include: 

1. employer’s liability insurance and workers compensation insurance covering personal injury or death of an employee of the contractor which specifies a capped level of liability per accident; 
2. commercial general liability insurance to cover injury or property damage; 
3. general third-party insurance for any accident or series of accidents covering the operations of the contractor; 
4. excess liability insurance; and 
5. insurance for any vessels involved with the project. 

An experienced contractor would seek to exclude third party liability but if not possible, it would best obtain a cap on liability, usually to the level of the contractor’s insurance. In cases of wilful misconduct or gross negligence the contractor may agree to unlimited liability, but this should be resisted.

Dispute resolution clauses are not complicated under LOGIC or CRINE. Although a party may include a provision for ADR, in particular, arbitration which is at the forefront of dispute resolution methods, there is no defaulting clause to any form of ADR. Other options available include mediation; conciliation; dispute review board (which can be just as effective and efficient); adjudication (although oil and gas operations are exempt from the Housing Grants Construction and Regeneration Act 1996 (HGCRA), the parties can agree to submit themselves to adjudication of certain issues). There is no reason the parties cannot have their own procedure for adjudication, similar to the HGCRA yet provide more generous time provisions for submissions and evidence gathering so neither party has an advantage over the other.

The failure of the parties to resolve a dispute does not automatically trigger the arbitration process, and for many reasons a superior alternative to commencing proceedings in national courts. The arbitration clause should include the seat in a highly advanced contract law jurisdiction which does not provide punitive damages as a remedy (i.e. US). Throughout the world the laws of England and Wales are preferred. ⁴¹

The escalated dispute clause within LOGIC initially refers dispute to representatives of the parties. If agreement cannot be reached, the dispute is then referred to the persons nominated in Appendix 1 by the parties. Failing this, the dispute is brought before the managing directors of the parties. Should the parties still not come to any agreement, then either party may commence court proceedings. 

Coming to agreement

The contractual process begins with discussions usually protected by a confidentiality agreement. After initial discussions the parties either proceed or pass. If they proceed, a draft is negotiated and executed by authorised executives. 

With PSA’s the contractor’s risk is the cost of exploration. ⁴² If he does not find commercial quantities of oil then the contractor bears the cost. If oil is found in commercial quantities then the contractor is reimbursed his capital costs and ongoing operating costs.

Some PSA’s are for exploration only and development and production is to be agreed after the exploration phase. This serves as a problem as the right is an agreement to agree which cannot be legally enforced. The IOC may spend large sums of money on exploration to end up outmanoeuvred by another IOC with its exploration costs forever lost. This is understandably unattractive for IOC but it all comes down to bargaining power. 

Due to the relative scarcity of oil and the numerous oil companies there is no alternative but to agree with the HG’s demands or another company will take your place. For example, in 1993 a multinational consortium signed an exploration agreement with Kazakhstan covering north of the Caspian Sea. This was the billed as the biggest seismic survey in history, 3 years at a cost of US$250 million. The exploration agreement included a right to negotiate a PSA over the area. In this situation the consortium managed to secure a PSA but the Kazak government regularly seeks renegotiation as it believes it received unfair terms.

A limit, expressed as a percentage of production, goes to the contractor for cost recovery. Management committees are formed to verify costs recovery submissions and scrutinise contractors claimed costs. These costs may include capital costs and operating costs such as repairs. Operating costs have priority and are recovered in the year they are incurred, while capital costs are recovered over the term of the agreement. If the contractor has bargaining power, then he can reduce his risk by demanding interest on his capital cost. In the Middle East the charging of interest is forbidden by the Koran.

The recovery of capital costs are made in payments of oil. This becomes complicated as capital costs must be converted into volumes of oil which take no account of transaction fees and transportation costs. Contractors prefer to have each barrel valued on a netback pricing. Another issue is timing, when do you value the oil? Actual sale price at the well or when the oil is transported to the buyer? Oil prices are volatile and any delay in transporting the oil could be beneficial or adverse depending on the market.

There are risks in determining profit shares which lead to disputes. What if there is more than one development in the PSA, will the contractor be entitled to recover the costs of the second and subsequent development from production of the first? Initially, one would turn to the contract. These profit-sharing mechanisms are best determined by economists and finance experts who have deep knowledge and understand the workings of PSA’s. However, developments are usually ring-fenced so that costs of the second development are recovered only from production of that development. 

PSA’s usually contain stabilisation clauses where the HG agrees not to change any term of the agreement and not expropriate assets of the contractor for a specific period. If a change in government or laws which reduces profitability to the contractor, the parties may renegotiate in order for the contractor to return to its original financial position. ⁴³

Two cases regarding stabilisation clauses were Texas Overseas Petroleum Company and California Asiatic Oil Company v Government of the Libyan Arab Republic ⁴⁴ and Libyan American Oil Company v Socialist Peoples’ Libyan Arab Yamahirya ⁴⁵. In the Texaco arbitration the arbitrator held that the act of nationalisation by the Libyan Government was a breach of the stabilisation clause and illegal under international law. Texaco was entitled to restitution of the concession. 

In comparison, the LIAMCO arbitrator decided that the existence of a stabilisation clause was not effective to prevent the Libyan Government’s act of nationalisation. So long as the act of nationalisation was accompanied by appropriate compensation then the act was a legitimate right of the state. Today, PSA’s focus on the consequences of nationalisation rather than holding off nationalisation.

This may provide some comfort to a contractor but it is merely an agreement to agree which cannot be legally enforceable. The trend now is to exclude environmental policy from stabilisation clauses so that the environment is not compromised when new matters arise consistent with IOC’s who vocalise their support for the environment.

PSA’s governing law provision usually provides for the local law. The problem is that usually the local law is very underdeveloped regarding contracts and their enforcement. To overcome this disputes are referred to arbitration in a neutral country with an advanced legal system. Litigating in the courts of the HG is not is not desirable and should be avoided if possible. IOC’s prefer to have contracts governed by an advanced system of contract law in a recognised legal jurisdiction. If a HG insists on its local laws it may be difficult to resist without insulting and offending the HG. The usual argument runs along the lines of, “our oil is good enough for you, but our law is not?”

 This brings us to the issue of “sovereign immunity” from all forms of legal action, also known as the doctrine of Act of State. In Sapphire International Petroleum Limited v The National Iranian Oil Company ⁴⁶ the court rejected the claim of sovereign immunity in this pipeline contracts case because:

“the present case does not involve the actual exploitation of oil resources by the defendant… the defendant contracted with the plaintiff on a purely private commercial basis… It did not carry out any oil-related activities on a sovereign basis. The conclusion of the contracts for oil and gas pipelines was at most a preliminary step or a sequel to possible sovereign activity.” ⁴⁷

To avoid sovereign immunity claims it’s best to seek a waiver of immunity within the PSA, failing which, procure the appropriate insurances. If insurance cannot be obtained, consider reassessment of the project. The classic examples include African nations which regularly have military coups or change political regimes. Is the PSA negotiated with the former government worth the paper it’s written on? This issue is not limited to Africa. The fall of the Soviet Union in 1990 caused massive confusion about deals struck with the former government, not only in relation to Russian fields but in newly created states bordering the Caspian Sea.

In order to avoid such a scenario is to have the PSA enacted as law by the HG’s parliament. Any challenge to the PSA would be significantly more difficult to substantiate. Renegotiation of long-term contracts should also be included. It is not unusual for HG’s to seek to renegotiate terms. The sanctity of contracts is not respected throughout the world especially when dealing with natural resources; however, renegotiation can be used to adjust to changes in economic and political circumstances to alleviate an injustice or unfair treatment upon a party to the agreement. ⁴⁸

Upstream projects are usually executed by joint venture (JV), incorporated or unincorporated, as the financial and logistical resources required for upstream projects are daunting. Even the majors prefer to have a 30% interest in half a dozen projects than 100% in one. HG’s also prefer to grant projects to a consortium rather than to a single company. In Norway and Angola the government usually chooses who will be in the consortium. 

An incorporated JV requires the formation of a company where shareholders are the prospective co-venturers and the constitution of the company serves as the agreement that dictates the relationship. If the JV is incorporated, it’s usually at the request of the HG. Other ancillary agreements, such as a shareholders agreement, also need to be drafted.

An unincorporated JV does not require the incorporation of a new company as the relationship of the parties is governed by the joint venture agreement (JVA). Upstream projects are more than not unincorporated as an incorporated venture would reduce the party’s freedom in making decisions regarding company law and tax issues. The HG is usually not a party to the JVA.

Joint operating agreements and joint venture agreements under the UKCS

Usually JOA’s are between the party’s to the project and without the HG. It details the relationship, rights and obligations between the parties’. JOA’s are almost always identical in nature wherever you go in the world. As a consequence, this gave rise to the birth of standardised JOA. One of the first was by the Association of Petroleum Negotiators (AIPN). AIPN produced an international JOA and has numerous other petroleum industry standardised contract forms.

Under a JVA each party is responsible for its percentage share of obligations which are owed to the HG by all in full on a joint and several basis. Prior to negotiating with the HG, the party’s enter into an Area of Mutual Interest Agreement (AMIA) or Bidding Agreement (BA). This agreement commits the parties to co-operate for a specified period, usually a bidding round, geographical area and if successful a full JVA is finalised. The party’s interests are identical and securing the project is the common goal. The preliminary agreements are not usually contentious but if they are the parties are not bound to continue and there is no obligation to proceed. 

JOA provide for two things:

1. they outline the manner in which the parties will conduct the negotiation phase; and 
2. it will detail the operation phase if the parties are successful. 

The negotiation phase will include the sharing of information; outline each party’s responsibility; the manner in which decisions are made; details of the proposed program and budget; and the sharing of costs. 

The operation phase will identify the operator; the respective interests of the parties; and voting rules. Sometimes, parties negotiate the JOA in advance and attach it to the Bidding Agreement which reduces issues and conflicts. However, if the bid is not accepted then time and money are wasted.

All AMIA’s contain four elements: 

1. opportunity; 
2. duration; 
3. no obligation to participate; and 
4. exclusivity.

 

Without the opportunity the agreement is futile. Opportunity may arise in the public forum or after private talks with a resource holder. Usually a confidentiality agreement is entered into so that the information does not leak to the public or a third party. The sanctity of confidentiality agreements are observed. The agreement is usually for five years and in the case of more sensitive material a substantially longer period is not uncommon. If the confidentiality agreement is breached, damages from the disclosee or an injunction/interdict to stop further breaches are sought.

The agreement has to have an appropriate duration so the opportunity may be negotiated, which at times could be months or even years. Where an AMIA expires prematurely because the parties have underestimated time, then these agreements usually include terms, whichever occurs first, as follows: 

1. a joint decision by the party’s not to make a bid; 
2. notification that the bid is rejected; or 
3. a successful bid and a JOA to determine the rights of the party’s from then on.

The parties are free to decide whether to proceed with a bid or to participate. There is no obligation to participate, however, after making that decision, that party may not then pursue the opportunity on its own or with others. Any risk of this happening is very small as the offending party will find itself in legal proceedings.

The heart of the AMIA is the exclusivity arrangement, to the exclusion of all others. This would also include a party’s affiliates or subsidiaries “from time to time”, so that there are no competing bids and the words “from time to time” don’t just apply as at the date of the bid, but also at any time in the future. Mergers or takeovers, as was seen in the late 1990’s, created a plethora of litigation due directly from this clause alone.

When companies become affiliates of another due to a merger, acquisition or takeover, the exclusivity arrangement causes issues when the “affiliates from time to time” clause is included. If the AMIA prohibited competition by affiliates then the whole new group was bound by two completely inconsistent obligations. The best thing to do is for the new group to withdraw from the AMIA altogether but some are reluctant if the opportunity is rich in oil deposits like the Middle East or the Caspian Sea.

Although the provisions regarding sole risk ⁴⁹ are unnecessarily complex, the UKOOA standard JOA for the UKCS is quite useful. The parties are jointly and severally liable to the resource holder, the UK government. In practice, if one party does not meet its participating interest share of costs or takes a disproportionate share of production, it leaves the other party’s meeting the defaulting party’s share of costs, which is called a “carry”. The common example is a resource holder/HG which has a carried share in the joint venture under a PSA.

There is fierce competition as to who becomes operator. Under a JOA usually the largest shareholder is appointed operator for the project.⁵⁰ The reason for jostling to become operator lies in the fact that operators run the project. However, in doing so, the operator cannot claim additional fees. The general rule is that the operator neither makes a gain or a loss and its costs are borne by the whole group according to their participating interests. Clause 5.3 and clause 5.4 allow for the removal of an operator in certain circumstances such as insolvency, but operators don’t relinquish control without great resistance. Generally, to remove an operator requires the unanimous decision of all non-operators and the operator must have breached its obligations or committed wilful misconduct. 

Notwithstanding, an operator is not liable for any error or mistake unless it arises from wilful misconduct or its failure to take out insurance. Any loss that’s not as a result of wilful misconduct is shared by the group according to their participating interests. However, under the UKCS liability for consequential loss or production loss is generally excluded rendering the operator immune from these actions including wilful misconduct.⁵¹

The sole risk provisions ⁵² are seen to be the most complex part of the agreement. Sole risk provisions are for specific operations proposed by a party and the operations committee (OC) rejects them. Any party that voted in favour of the proposal has a right to conduct those operations at its own risk and expense.

Typically, prior to activating the sole risk provisions there is a procedure to follow. To illustrate, let’s say the OC rejects a proposal to drill a well. The party(s) that voted in favour may proceed at its own risk but if the party(s) seeking to drill holds a total participating interest equal to or greater than the voting pass mark for drilling a well, then the well is drilled as joint operations requiring all parties to the JVA to join and pay their share. However, if they do not possess the pass mark necessary, then the operator drills the well on their behalf at their own risk and expense. If they are successful, then the party(s) that did not contribute to the costs may only participate in the subsequent development of that discovery when it pays the sole risk party(s) a penalty, usually ten times the amount of its share of the cost of the well. 

These provisions allow a minority shareholder to initiate action even though it would have no effect on the OC. In a way, this protects the minority shareholders so they are not pushed around in the JV. In reality, minority shareholders don’t demand the development of an area or drilling a well without having geological and seismic data to support its position otherwise they run the risk of drilling a dry well which drains their resources. The same applies to sole risk development.

One of the rarest⁵³ forms of default under the JOA⁵⁴ is where a party fails to meet an invoice in full as required under the agreement.⁵⁵ If the defaulter fails to remedy this default within 60 days of issue of the invoice it will forfeit its entire participating interest without compensation. The other parties agree as to how the defaulting party’s interest is to be allocated amongst the group, thereby increasing their share and cost. These provisions might seem draconian but the petroleum industry is capital intensive and any party not meeting its financial obligations will not be tolerated and severely penalised. Upstream activities are vital to the world economy, a serious business and any failure to pay will risk your share of the project.⁵⁶

In the 1970’s Burmah Oil defaulted due to insolvency. No further defaults were recorded for insolvency. The next reported cases relate to new smaller participants when the majors left the UKCS in 2005 - 2006. As a result the DTI increased financial scrutiny of new participants in the field.

Another issue in JOA’s is whether a party can assign⁵⁷ its interest or withdraw⁵⁸ from the JV? Any transfer bears the risk that approval is withheld by the group but such approval cannot be unreasonably withheld.⁵⁹ Since 2003 the UK government banned pre-emption rights within JOA’s because any good deal made by a prospective purchaser would warrant the group to exercise its pre-emptive rights to purchase. However, if the prospective buyer overpaid, the group would let the assignment proceed, thereby notifying the prospective buyer as to the unfavourable terms of the sale rendering these assets to be overpriced. This was not the government’s aim.

The Master Deed developed by Oil and Gas UK Progressing Partnership Working Group (PPWG), BERR, and a number of other interested organisations greatly expedites the transfer of UKCS offshore licence interests and other agreements relating to associated assets and infrastructure. It also introduces a standard pre-emption regime to give confidence to incoming companies.

In a JVA, a simple sale of an interest, that is, the purchase of shares, the most contentious clauses are usually the warranties. A “warranty” is a statement made by the seller regarding an aspect of the target company. To prove a breach of warranty the buyer must show that the breach reduced the value of the company and the loss can be quantified. An “indemnity” obliges the seller to reimburse the buyer for a specific liability in the event it arises. Warranties are also provided on employees, pensions, financial records, management accounts, annual accounts, taxation, insurance, intellectual property rights, information technology systems, environmental compliances, abandonment requirements and health and safety issues.⁶⁰

The seller must be able to warrant that it owns the interest and the right to realise it, and must show that it has not breached any terms of the licence and, more importantly, is not in default of the JOA. Any assets included in the sale must be free of encumbrances. From a seller’s perspective, this is where warranties end. 

The seller will not warrant the subsurface or the geological and technical information that it has in its possession. To limit its exposure the seller would include limitations on these warranties so that: 

1. any claims are made within a certain time. The seller would be looking for the shortest time possible;
2. if a claim is made, that claim must be above a certain value (the “de minimis” limit); 
3. no claim can be made where the total claims fail to reach the de minimis limit (the “de maximis” limit);
4. no claim can be made if it has been disclosed or within any of the field agreements or if there is a change in legislation.⁶¹

The buyer must accept this as no seller will provide a warranty that petroleum deposits are present in the field which is for sale. This risk is borne exclusively by the buyer, but it would be prudent for the proposed buyer to undertake his own geological surveys and seismic tests. Farm–in and farm–out agreements raise the same issues but with a farm–in the buyer does not pay cash for the interests, but earns them by performing operations on behalf of the JV. An owner would prefer to sell his interest for cash and be free of risk than to farm–out with continued exposure and additional costs.

All JOA’s contain a provision that the agreement does not extend to the joint sale of petroleum and each party is responsible for the disposal of its share of production. The reasoning is to avoid the inference that the group is manipulating the markets. This is not the case for gas JOA’s because, unlike oil, it’s difficult to lift and dispose of gas and so the group usually agrees to joint sales. Although JOA’s create issues that can develop into contentious matters, they are few and far between when compared to unitisation agreements (UA’s).

Unitisation Agreements

Unitisation, more commonly known in the US as “pooling”, occurs when a field is discovered that underlies more than one licence of a contract area.

Such a field cannot be developed under either JOA but in the spirit of economic development and efficiency it would be ideal for a single development. The agreement used for such a project is called an Unitisation and Unit Operating Agreement (UUOA) and this agreement supersedes and replaces the JOA but only in regard to the field. The JOA still defines the relationship of the parties and any other area of development within the field. 

Under UA’s each party has veto power risking delayed production, sometimes for years, due to the incessant demands of a party. To avoid this dilemma the DTI (now DECC) would not allow development of the cross-boundary field until all parties have agreed. If the parties resist agreement, the DTI has the power to impose a unitisation scheme, although in practice this has never occurred. The critical issue is how does one determine the share of each group? UA’s refer to this as “tract participations”. The easiest and most common method is the stock tank oil originally in place (STOOIP). A more appropriate, but equally difficult, method is to calculate the reserves that will be produced, that is, the economically recoverable reserves (ERR). The process is a nightmare when dealing with gas.

What is common in all UA’s is how much oil lies on how much of whose field? An example of a field lying across five licence areas was at Britannia and Clair Fields. 

Another is the Scott Field discovered in 1985 by Amerada Hess and Amoco. Here, a confrontation erupted where both claimed operatorship and that the majority of the field lay in its licence area. Development plans were produced, each preferring their own, and each naming the fields Waverly (Amerada) and Brunel (Amoco). Millions of dollars and three years later, Amerada won operatorship. The field was unitised on provisional tract participation of 50/50. The first re-determination took two years, 15 people were involved on a full-time basis from both sides and the final outcome was litigated before the UK courts for another year. The court ruled in favour of Amerada adjusting tract participations to 52.4/47.6. It was rumoured the 2.4% increase, with a value of US$25 million, cost a conservative US$175 million in legal and other fees.⁶²

Today, these disputes are referred for expert determination based on technical information available. The information is usually geophysical, petro-physical, geological and reservoir engineering. This form of dispute resolution is widely used and although time consuming initially, it is significantly advantageous to court proceedings.

The re-determination of tract participations poses difficult applications of provisions that are not easily understood or applied. What happens when insufficient production remains to allow the underlifted group to make up the shortfall of any re-determination? 

This occurred in the case of the Fulmar oilfield where the first re-determination increased the tract participation of the majority group, Shell and Esso, from 85% to 93.9%. In the end Shell and Esso paid an increased share of costs without fully recovering their underlifted production.⁶³

With a unitised satellite development in the North Sea of about 1 million recoverable barrels, traditional UA’s cannot be justified and re-determinations should be forgotten. It is evident that at this stage of the game, parties need to agree to fixed tract participations. Over the years larger fields have been developed on a fixed equity basis. These include: Miller (1987) a geologically complicated field with estimated reserves of 347 Mbbls and 500 bcf of associated gas; Armada (1994) comprised of three gas condensate fields with estimated reserves of 70 Mboe and 1.2 tcf of gas; Clair (1995) this oilfield with an estimated 2 - 3 billion barrels of heavy oil with a low recovery factor which extended across five licence areas.⁶⁴

Another technique available to counter unitisation disputes is where two groups cross-assign interests in the two licence areas (or more if so deemed necessary) by way of purchase or swap so that only one group holds the same participating interest across both licences. As a result the entire area, not just the field, can be developed under a single operating agreement.

The UKCS developed by equalising interests in the following fields: Liverpool Bay (1993) estimated reserves of 183 Mbbls and 1.1 tcf of associated gas; Britannia (1994) field with gas condensate and reserves estimated at 117 Mboe and 3 tcf of gas extending across five licence areas; Bruce (1999) geologically complex gas condensate field with estimated reserves of 237 Mboe and 2.5 tcf of gas; Buzzard (2003) oilfield that came online in 2007 with estimated reserves of over 500 Mbbls. Oddly enough this field lies near acreage previously relinquished by Amoco. This is the largest oilfield discovered on the UKCS in 21 years.⁶⁵

Decommissioning deeds

In the UKCS every JOA⁶⁶ and UUOA requires conditions relating to decommissioning and for providing abandonment security. Section 29(1) of the Petroleum Act 1998 and Model Clause 19 of the Standard Offshore Production Licence outline the obligations for abandonment and decommissioning of offshore installations. Model Clause 19 states that a licensee may not abandon any well without the consent in writing of the Secretary of State (SoS) and must comply with all conditions placed by the SoS on the consent.

The costs of decommissioning a field are borne exclusively by the parties to the JOA in their participating interest shares. The risk with decommissioning, apart from the technical and environmental, is financial. Will the parties have the necessary funds to decommission the facility? Where a party in a group defaults the non-defaulting group members remain jointly and severally liable for all costs associated with decommissioning. Even if the defaulting party’s interest is forfeited it becomes futile when there is insufficient production to cover the cost of decommissioning. 

In order to avoid such an outcome, decommissioning deeds (DD) are executed between the parties’ earlier in the project with some form of security against these costs. The security can come in the form of a letter of credit from a bank or a performance bond where the slightest breach of the DD would direct the security to be paid directly to the group. 

The most resisted form of security is cash paid into a trust account explicitly formed for decommissioning. Parties prefer not to leave vast sums of money in trust accounts when they could borrow against it to fund the next project. Also, the tax consequences are anything but positive. Abandonment security provisions are much more advanced than 10 to 15 years ago. Parties are too aware of defaults which are now unheard-of thanks largely to the DD which supplements the decommissioning clauses in the JOA. 

Liability provisions in UKCS oil and gas transportation agreements

The Forties System (FS), owned by BP, is one of the major transport hubs for oil from the UKCS. The liability provisions are almost identical for all field users and attempting to negotiate would be futile. Needless to say, the provisions are in favour of BP.

The liability provisions state that oil in the system is, firstly, owned by the field groups on a pro rata basis to input and secondly, each field group is liable for any loss of or damage to its production while it is in the system. BP carries no liability. The most prevalent are fire and explosion which could result in damage to the structure, death or injury to workers, pollution, delay or production stops having severe knock on financial effects. The mechanisms used to soften the actual occurrence of a risk are well drafted clauses in contracts requiring control checks, qualified and trained personnel together with insurance. 

These liability provisions include that BP is never liable for the failure of the system or inability to transport. BP has been known to agree to transport a certain quantity of future production at no charge due to a system failure. The standard clause regarding “consequential loss” applies, thereby prohibiting any party to sue for loss of production.⁶⁷

In addition, parties are responsible for the death of or injury to its own people whatever the cause. Each party is responsible for damage and for ensuring its own system, with the exception of damage caused by “wilful misconduct” by another party.⁶⁸ 

Gas transportation agreements are similar but more complicated due to the chemical state of gas. The most complicated aspect of gas transport agreements is knowing the capacity requirements ahead of time. With oil liquids required capacity can be estimated for months, sometimes even years in advance. The same cannot be said with gas. Capacity changes are volatile and change constantly from literally minute to minute. As stated earlier the financial repercussions (penalties and tariffs) for failing to deliver make these agreements the most complicated of all the upstream agreements.

This raises the question, how would an agreement between the system owner (with many parties) affect liability between numerous other parties also using the system especially when there is no contract between the users? What if one user group caused the shutdown of the system thereby affecting production of the other users? In theory, other users could sue for loss of production if negligence can be established.

Such a scenario is not possible as each party wishing to use the FS must execute a Common User Liability Agreement which applies between all users of the system forbidding a user from suing another for any loss of production. This is similar to the liability provisions in the Transport Agreements discussed above.⁶⁹

Contracts in the European gas market

The European gas market and, to some extent this is also applies to, oil markets have numerous risks. These risks include the:

1. depletion of reserves. The speed at which our energy reserves are being depleted is subject to controversy known as “peak oil”. To make any educated determination one must look at proven reserves and the production rate. This will provide some idea of the remaining reserves;
2. structure of supply contracts; 
3. investment regime. Foreign investors prefer open investment without any restrictions on exploration and production. Having direct access to energy reserves can guarantee energy security but this usually comes with strings like transfer of technology and know-how; type and form of investment contract to be used; the HG’s participation in the investment. Prior to investment in restrictive countries, verification of reserves should be undertaken. At the same time “it is equally important that investors have access to the infrastructure projects of the exporting countries and establish contracts with these countries with “reciprocity clauses” that enable exporting countries’ companies to invest in importing countries’ infrastructure projects as well.” This provides for investment in downstream operations by vertical integration in the importing country. 
4. insecurity of energy sources; 
5. insecurity of energy transit routes. The EU would like to see more countries implement the ECT and the Energy Charter Transit Protocol which provides common rules for investment, trade and transit rights. At the 6th annual EU – Russia summit on 30 October 2000 in Paris it was agreed to institute an energy dialogue to enable progress for an EU – Russia Energy Partnership. How this Partnership will be affected in view of the January 2009 cut off of gas supplies by Russia into Europe is yet to be ascertained. These agreements and protocols give Europe a sense of security, thereby reducing the risk of energy cut off; and 
6. insecurity of energy facilities.⁷⁰

However, this paper will only address the structure of supply contracts. Supply contracts mobilise the required energy effectively and efficiently to the UK market. In Europe, monopolies were created and they dealt with supply and demand issues which brought a level of confidence to the market. However, the market has been liberalised by virtue of the Gas Directive 98/30/CE, Electricity Directive 96/92/CE and subsequent directives⁷¹ which ended monopolies in transport, distribution and sale.⁷²

Eligible customers can satisfy demand through operators, transporters or distributors. The switching between the three threatens transporters and distributors because they are not confident that the energy purchased via long term contracts will be purchased by a customer. The EU anticipated this and in the preamble of the Gas Directive 2003 addressed these contracts by stating: 

“Long term contracts will continue to be an important part of the gas supply of Member States and should be maintained as an option for gas supply undertakings insofar as they do not undermine the objectives of this Directive and are compatible with the Treaty, including competition rules. It is therefore necessary to take them into account in the planning of supply and transportation capacity of gas undertakings.”

The International Energy Agency (IEA) stated the importance of this type of natural gas contract as follows: 

“there is no doubt that the type of contract concluded in the past has provided a good basis for securing gas supplies in Europe in general and in particular that it has been instrumental in providing the basis for developing new gas supply projects in a situation where the gas has been introduced into new countries or has seen rapid expansion in existing markets”.⁷³

The EU does not prohibit long term contracts as it believes that they are the best source of supply security. There are arguments for and against long term contracts.⁷⁴ However these contracts provide restrictive provisions whereby under EU law they could be regarded as anti-competitive and “deemed problematic because they were found to have a de-facto exclusive character, leading to a foreclosing effect in the market”.⁷⁵ They contained “own use requirements” or “destination clauses”. Destination clauses prohibit the buyer to re-sell oil or gas. Energy companies were at a juncture.

Energy exporters resisted the removal of destination clauses in order to guarantee control over their end markets deterring buyers from reselling energy on other gas markets at a higher price. The European Commission (EC) insisted these clauses be abolished at the risk of an inadequate energy supply. The EC considered this to be a violation of Article 82 of the ECT because it had the effect of maintaining an existing dominant position of a select company in a particular Member State. The EC required existing contracts within the EU be modified. An example was the EC’s investigation over long-term gas supply agreement between Spanish Gas Natural and the electricity company Endesa. Once the companies modified the terms of their agreement to comply with EU law the investigation was closed.

The new Directives had the effect of loosening the exclusivity and term of the contract so as to “avoid the excessive dependence of the customer on the supplier and allowed the buyer to resell the gas”.⁷⁶ After long intense negotiations with Gazprom, Nigeria LNG and Algeria’s Sonatrach, long term contracts remained but without restrictive clauses.  

Contracts were amended to comply with competition laws but effectively remained the same. A “take or pay contract” is one type of a long-term agreement. The buyer is obligated under the normal take-or-pay provision to either take delivery of the minimum quantity or otherwise pay for the shortfall from the agreed minimum quantity over a specified period. 

For example, if a contract requires the buyer to accept 80% but can only receive 50% of that delivery due to a fall in demand, then the buyer shall pay for the 30% shortfall. These contracts range from 15 to 25 years providing gas suppliers with secure cash flow and buyers with long-term gas supplies. The EC has reduced the take-or-pay provisions from 80-90% to 50-60% of the purchase amount.⁷⁸

However, in January 2005 Algeria reached agreement with the EU which provided that “the EU will continue to allow destination clauses, and Algeria will share the profits of any gas sales to third parties with the original buyer”. Algeria, and other energy producing countries, realised that it would be better to maintain these long-term contracts in the revised EU form than abandoning them altogether. A states future and growth rely heavily on a strong steady source of money. One matter that has been overlooked by the EC, maybe intentionally, is the fact that restrictive clauses in long term oil contracts were never discussed. 

Conclusion

There will always be an element of risk within petroleum contracts. On the UKCS LOGIC has tried, to some extent, to limit these risks. The one thing that is always prevalent in these contracts is the political aspect. Political circumstances are constantly changing and a government, even the UK government under the guise of national security, may at any time seek to alter any agreement based on geopolitics.

 

 

¹ John D Rockefeller (8 July 1839 – 23 May 1937) founder of Standard Oil Company, University of Chicago, Rockefeller University, Central Philippine University, General Education Board, and Rockefeller Foundation.

² There are numerous health and safety laws that must be adhered to, including: The Health and Safety at Work, etc. Act 1974, Part 1; The Offshore Installations and Pipeline Works (Management and Administration) Regulations 1995; The Offshore Installations and Wells (Design and Construction etc.) Regulations 1996; The Offshore Installations (Safety Case) Regulations 2005 (which replaced the 1992 Regulations). John Wils & Ewan Neilson, “The Technical and Legal Guide to the UK Oil and Gas Industry”, 2007 pp 214 - 215.

³ John Karlberg, “Renewable Energy Issues – Topic 7: Significance of Aberdeen in RE”, RGU 2009 p 2. 

⁴ Monte Carlo simulation was invented by physics researchers Stanislaw Ulam, Enrico Fermi, John von Neumann, Nicholas Metropolis and others. The name is a reference to the Monte Carlo Casino in Monaco where Ulam's uncle would borrow money to gamble. Monte Carlo methods are useful for modeling phenomena with significant uncertainty in inputs, such as the calculation of risk in business, finance, engineering, supply chain and science.

⁵ A Beta coefficient is based on the historical volatility or return on shares in relation to the overall stock market index.

⁶ The terms “contractor”, “IOC”, “operator” is used interchangeably with investor.

⁷ The term “resource holder”, “State”, “Host State” are used interchangeably with Host Government.

⁸ A thorough and thoughtful discussion on expropriation by States can be found by Ernest Smith, et al., “Materials on International Petroleum Transactions”, 1st ed 1993, Ch 3.

⁹ Part III Investment Promotion and Protection, Article 10: Promotion, Protection and Treatment of Investments.

¹⁰ Chris Thorpe, “Fundamentals of Upstream Petroleum Agreements”, 2008 pp 59 – 63

¹¹ Ibid, pp 75 - 101.

¹² Ibid, pp 102 – 106.

¹³ Dennis Stickley, “A Framework for Negotiating & Documenting Petroleum Industry Transactions”, (2006) p 84.

¹⁴ Ibid, pp 83 – 84.

¹⁵ The Engineer, “British National Oil Corporation”, 29 July 1982, 5 August 1982.

¹⁶ Edwin Unsworth, “UK will allow BP to complete Britoil takeover”, 23 February 1988.

¹⁷ Clause 14.

¹⁸ Clause 15.

¹⁹ Clause 38.

²⁰ Clause 17.

²¹ op. cit, Chris Thorpe, pp 109 - 110.

²² Ibid, p 18.

²³ Genevieve Macattram, “How Can the Indemnity Clause Expand or Limit the Responsibility for Liability of the Parties in International Oil and Gas Contracts?” (2005) pp 4 - 5.

²⁴ Ibid.

²⁵ Ibid, p 5.

²⁶ Ibid, [1960] CA (Civil Division) 6 BLR 23, p 10.

²⁷ Ibid, pp 10 – 11.

²⁸ [1952] AC 192 at p 208.

²⁹ Alderslade v Hendon Laundry Ltd [1945] KB 189.

³⁰ [1994] 1 WLR 1515.

³¹ [1993] 2 Lloyd’s Rep. 582.

³² LOGIC – Standard Contracts for the UK Offshore Oil & Gas Industry.

³³ Interestingly, “Good Oilfield Practice” is also defined at clause 1.1 of the JOA.

³⁴ (1854) 9 Ex. 341. This division has been accepted throughout the common law world and even the US where this case is cited.

³⁵ op. cit, Genevieve Macattram, p 15.

³⁶ [1998] WLR 896 (HL).

³⁷ [1949] 2 KB 528.

³⁸ (1997) 87 BLR 87. These clauses are mostly found in IT contracts and for the supply and installation of goods and materials.

³⁹ [1991] LLR 387.

⁴⁰ If this ground is used to terminate the contract, the operator will be obligated to reimburse the contractor for costs directly incurred and which are non-recoverable because of the termination. 

⁴¹ Paul Griffin, “Transnational Gas Projects and their Agreements: Part 3”, International Energy Law & Taxation Review (2002). The advantages to choosing English law as the governing law in petroleum industry agreements are found at p 6.

⁴² op. cit, Chris Thorpe, p 23.

⁴³ op. cit, Paul Griffin, pp 1 – 2.

⁴⁴ (1978) 17 I.L.M. 3.

⁴⁵ (1981) 62 I.L.R. 140.

⁴⁶ (1964) 13 I.C.L.Q. 1011

⁴⁷ op. cit, Paul Griffin, pp 2 - 3.

⁴⁸ A detailed discussion with numerous examples of renegotiated petroleum contracts with the HG can be found in Dr Abba Kolo & Thomas Waelde, “Renegotiation and Contract Adaptation in International Investment Projects: Applicable Legal Principles & Industry Practices”, Oil, Gas & Energy Law Intelligence, Volume 1, issue #02 – March 2003.

⁴⁹ ibid, clause 15.

⁵⁰ ibid, clause 5. The press referred to “Shell’s Brent Field” when, in actual fact, Brent was a joint venture with Exxon.

⁵¹ ibid, clause 6.2.4.

⁵² ibid, clause 15.

⁵³ op. cit, Chris Thorpe, p 65.

⁵⁴ op. cit, UKOOA - clause 17.

⁵⁵ Ibid, clauses 17.1 and 17.2.

⁵⁶ Ibid, clauses 17.6 and 17.7.

⁵⁷Ibid, clause 23.

⁵⁸ Ibid, clause 24.

⁵⁹Ibid, clause 23.2.

⁶⁰ op. cit, John Wils & Ewan Neilson, pp 101 - 102.

⁶¹ Ibid, pp 93 - 94.

⁶² op. cit, Chris Thorpe, p 82.

⁶³ Ibid, p 83

⁶⁴ Ibid, p 87.

⁶⁵ Ibid, p 89.

⁶⁶ op. cit, UKOOA, clause 13 and Schedule C Decommissioning Cost Provision Deed.

⁶⁷ op. cit, Chris Thorpe, p 150.

⁶⁸ Ibid, pp 153 – 155.

⁶⁹ Ibid, pp 159 – 160.

⁷⁰ Sanam Haghighi, “Energy Security: The External Legal Relations of the European Union with Major Oil and Gas Supplying Countries”, 2007 pp 18 - 32.

⁷¹ Directive 2003/54/EC 26 June 2003 in relation to Common Rules for the Internal Market in Electricity and repealing Directive 96/92/EC, [2003] OJL/176/37. Also Directive 2003/55/EC 26 June 2003 with respect to Common Rules for the Internal Market in Natural Gas and repealing Directive 98/30/EC, [1998] OJL/204/2.

⁷² Article 23 of the repealing Gas Directive 2003 and Article 21 of the repealing Electricity Directive.

⁷³ “The IEA Natural Gas Security Study”, Paris, IEA, 1995.

⁷⁴ Jonathan Stern, “Traditionalist versus the New Economy: Competing Agendas for European Gas Markets to 2020”, London, RIIA, 2001 and also by Jonathan Stern, “Competition and Liberalisation in European Gas Markets: A Diversity of Models”, London, RIIA, 1998.

⁷⁵ op cit, “Energy Security: The External Legal Relations of the European Union with Major Oil and Gas Supplying Countries”, p 22.

⁷⁶ op. cit, Sanam Haghighi, p 23.

⁷⁷ Ibid, p 24. EIA Country Analysis Brief, Algeria, March 2005.

⁷⁸ Ibid.