1. Foreword

From now until the time you finish this sentence, another 5,000 barrels of oil will have come out of the ground. Or 10,000 barrels by the end of this one, worth about a million dollars on world markets today. Suppose we created a World Oil Production Index (WOPI) as a measure of money, like a light year in distance. WOPI would equal a spacious Central Park apartment in a minute, the most expensive skyscraper ever built, Burj Khalifa, in a morning, and the net worth of Facebook's Mark Zuckerberg in two weeks.

Or, alternatively, WOPI would surpass the GDP of the Democratic Republic of Congo, a country of 70 million people, in a day and a half, and the entire annual aid budget to Africa in four days. It would, in fact, take about two weeks of WOPI each year to eliminate absolute poverty among the 1.3 billion people around the world who subsist on less than $1.25 a day each. It's not news of course that oil generates a lot of money. But it's good to get a handle on just how much.

It is petroleum This is a footnote contracts that express how this money is split and who makes what profits, just as it is the contracts that determine who manages operations and how issues such as the environment, local economic development, and community rights are dealt with. The share price of ExxonMobil, the question of who carries responsibility for Deepwater Horizon, whether Uganda will be able to stop importing petrol, and how much it costs to heat and light homes in millions of homes -- these are issues which depend directly on clauses in the contracts signed between the governments of the world and the oil companies.

For most of the 150 years of oil production, these contracts have remained hidden, nested in a broader secrecy that surrounded all aspects of the industry. Governments claimed national security prerogatives, companies said commercial sensitivity precluded making them available.

But the last few years have seen the emergence of the the idea that these contracts are of such high public interest that they transcend normal considerations of confidentiality in business, and should be published. A few governments and companies have published contracts. Academic institutions such as the University of Dundee in the UK and NGOs such as the Revenue Watch Institute are just now, at the end of 2012, beginning to collect the contracts that are in the public domain into databases searchable over the Internet.

Contract transparency is the natural next stage of the transparency movement. The initiatives which began in the 1990s around 'Resource Curse', leading to the creation of the Extractive Industries Transparency Initiative in 2002, have succeded in opening up a public conversation. Governments and companies now acknowledge the importance of openness and ethical business. CSR was born to counter 'Blood Diamonds'. But there is as yet little systematic public understanding of how these titanic industries actually work. Activists and journalists sometimes penetrate dark corners and uncover kickbacks and secret deals, and occasionally trigger a public outcry that effects change. But public suspicion remains high around the world, fueled largely by this secrecy. In dozens of countries around the world public debate discussion continues with the main documents at the heart of this industry remaining absent.

Casual rhetoric about how "the government" or "the state" is being so secretive is not helpful because it misidentifies - and actually understates - the degree of dysfunctionality and asymmetry of information that can exist. This is often "deep state" stuff, belonging to a world of aides and special advisors with ill-defined roles, where the regular apparatus of the state can also be out of the loop. In one country, senior diplomats in its foreign ministry lack the most basic understanding of the industry that generates 90 percent of its revenues and governs relations with its neighbours, with whom it shares sizeable fields. In another, the finance minister himself has been denied access to the petroleum contracts which determine how much revenue he is supposed to collect from international oil companies and others. In a third country a bid round went bad, and contracts were delayed for two years, because a phone call to clarify basic details wasn't returned. Ministers of the economy, planning and environment are rarely consulted about how contracts can integrate into broader government policy.

And yet, because of the pioneering move to publish by some governments and companies, the chance now exists to begin to create public understanding of petroleum contracts, based on those that exist in the public domain. This book is a first attempt to rise to that opportunity. We aim to reach at least ten thousand people around the world who may be engaged in the industry, or in governance of or transparency activism around it, but who may not have had the chance to gain professional exposure to petroleum contracts and the issues of how they are actually negotiated. We hope they will include people in the public and private sectors of 50 countries, journalists and civil servants and local business communities as well as promoting a broader understanding of the negotiating process within the companies themselves.

The sections of the book are intended to lead the non-specialist reader through a logical sequence in understanding contracts. Section One sets the stage with background context. Section Two, who the players are, establishes the formal parties to a petroleum contract and the normal provisions of who does what and who decides what according to the contract. Section Three, 'The Money', goes to the heart of the negotiation and deals with all the different revenue streams and tools that go into constructing ever more complex financial arrangements.

Then we devote two sections to subjects which are handled in contracts but often in passing and at the last minute. Section Four deals with the linkages between the petroleum industry and economic development as a whole in the producing country, as dealt with in the contract, while Section Five looks at clauses relating to health, safety and environmental protection. Finally, in Section Six, Lawyers Yammering On, we look at pure legal aspects, dispute and arbitration procedures.

We quote liberally from a family of petroleum contracts throughout the book that come from eight countries - Afghanistan, Azerbaijan, Brazil, Ghana, Indonesia, Iraq, Libya and Timor Leste. They were selected to represent various structures in contracts, stages of development of petroleum industry and most of all because they are in the public domain. Other contracts are referred to from time to time.

This book has been written in five days from start to finish, using the Booksprint technique pioneered by Adam Hyde. I am writing this foreword as its last entry on a Friday afternoon at Schloss Neuhasen little more than 100 hours after we sat down to storyboard it. This is both a source of pride -- and our first and last defence when our colleagues and the broader community point out inaccuracies, gaps and other defects, as we hope they will and encourage them to do.

The Booksprint is a collaborative writing technique of astonishing power in which colleagues constantly brainstorm, write, edit and copy-edit each other in a workflow that somehow manages to combine high fluidity with structure. But inevitably in a process of such speed there will be uneveness and difference in tone and perhaps, at the margins, in substance, between one section and another. It is a work of collective authorship published under the Creative Commons license, but that does not mean that every one of us, or the affiliations we represent, subscribes to every statement made. This book is more team work than group think.

The writers of this book are: Peter Eigen, founder of Transparency International and founding chair of EITI; Cindy Kroon from the World Bank Institute; Herbert M'cleod from Sierra Leone; Susan Maples, Office of the Legal Adviser to Liberian President Ellen Johnson Sirleaf; Nurlan Mustafayev from the legal affairs department at SOCAR, Azerbaijan's state oil company; Jay Park, a lawyer from Norton Rose; Geoff Peters; Nadine Stiller from the German agency for international cooperation GIZ; Lynn Turyatemba from the NGO International Alert in Uganda; Johnny West, founder of the OpenOil consultancy; and Sebastian Winkler, Director Europe for Global Footprint Network. All work on the book was pro bono or mandated by the organisations we work for. If you want to hear each of us in our own words talking about the project, go to http://openoil.net/booksprint

Adam Hyde of SourceFabric (Booktype) and BookSprints.net facilitated the Book Sprint and Lynn Stewart designed the book and its art work. First readers, and copy editors were the OpenOil team of Steffi Heerwig, Robert Malies, Zara Rahman and Lucy Wallwork.

We received financial assistance to write this book from: Internews Europe, a media development organisation based in London; Petroleum Economist magazine (with no editorial input - our views and mistakes remain our own); and the German Federal Ministry for Economic Cooperation and Development (BMZ).

We want this book to be the start of a broader public conversation about petroleum contracts. It will be a living document, subject to constant critique on the Web and periodic review. Anyone can download it at any time, print and sell it, and adapt it. Please bear in mind, though, that because our work is Creative Commons license and available to everyone, the terms of copyright say that you inherit the terms of that license and any work you base on ours will legally be under Creative Commons license too.

We aim for the book to become the basis for localised versions which take a look at petroleum contracts country by country. There is no reason why, three years from now, there shouldn't be, for every country in the world with a petroleum industry (or hoping to develop one), an editorially independent and technically informed book put together by a group of sympathetic but objective professionals from a range of disciplines which analyses that country's core contracts, available to the public free of charge. We would be delighted to help make that happen with anyone in a producing country who has an interest.

We also aim to make it the basis for training courses, ported to all relevant locations and languages, which bring a fundamental and holistic understanding of petroleum contracts to a much wider audience than has had the chance to engage with them so far.

It is our belief that even though these contracts were not written with the public in mind, with a little effort they can be understood to a level which enables real, mature and informed public discussion. We hope that after reading this book you will agree.

 

 

Johnny West

Founder OpenOil.net

2. Petroleum Basics

You put it in your car. It heats your house. Flies planes. One day we might be beyond it, but today we are not. Petroleum. The material behind these critical functions that literally fuel the world, is made up of strings of carbon and hydrogen, known as hydrocarbons, formed from the compression of organic matter over hundreds of millions of years. Old stuff that drives the modern age. Oil, gas, petrol, diesel, butane - they all come from hydrocarbons beneath the earth's surface that are then are refined to make them more useful to us. This book is about the contracts that make finding and producing these substances possible right now.

The first thing that will probably come into your mind when you think about products that could be made out of all that petroleum is probably fuel. However, there are numerous other materials and products that contains oil or gas, e.g. toothpaste, candles, medicines, or even computers. This also explains why currently petroleum is of utmost importance to our lives today.

Historically, petroleum contracts were designed with crude oil in mind, and this continues to dominate the logic and structure of contracts today. Gas has only recently also become a valuable resource. As the old industry saying went: "What is worse than not finding oil? Finding gas!" This is not true any more, as gas becomes increasingly marketable. But not all contracts around the world have, as yet, caught up to this reality.

Natural gas, or just gas, is usually classified within contracts as either non-associated gas and associated gas. Non-associated gas refers to gas reservoirs that contain only gas and no oil, whereas associated gas is found together with crude oil. The implications of these can be far reaching and will affect environmental, social, political, fiscal and technological considerations. Countries with significant gas deposits will typically address these considerations in far greater details in their contracts than countries with primarily crude oil reserves.

The following diagram shows the three types of petroleum extraction and their comparative costs.

Offshore operations are more expensive than offshore operations because of the type of facilities and structures required. Deep-water drilling is much more expensive than shallow-water drilling because the platforms are technically more difficult to construct. These considerations are addressed in contracts by providing financial incentives (e.g. tax reductions) for those operations and stages of production that are more challenging, riský and costly to the contractor.

Conventional oil extraction employs traditional oil wells, and unconventional, the new and emerging technologies and methodologies allowing access to more inaccessible reserves, such as those found in oil shale and oil sands.

Conventional gas is typically “free gas” trapped in rock formations and is easier to extract. Unconventional gas reservoirs include tight gas, coal bed methane, gas hydrates, and shale gas (which sits in sand beds). Drilling for unconventional gas can be more expensive compared to conventional gas. The supply of and interest in gas extracted from unconventional reservoirs is growing rapidly, mainly due to technological advances.

....but as of the writing of this book, most contracts do not provide for the unique attributes of unconventional gas.

What does "Oil is at $100 a barrell mean"? All oil? Some oil? The answer to this is, "some oil".

Petroleum is being bought and sold at many different prices all over the world though they tend to be compared or "benchmarked" off certain common standards.

• For Oil, West Texas Intermediate (WTI) or Brent crudes or blends and commonly used.
• For Gas, Henry Hubb is common. 

These benchmarks, which are the prices that make the headlines, are used to determine the price of oil and gas produced elsewhere. This will be discussed in more detail later in the "Valuing Oil" chapter.

Nowadays, with the price of oil being high, there is an increasing movement of people in resource-rich countries wanting visual proof that their natural resources are directly benefiting them. From their position as citizens of the country and therefore as co-owners of the resource, there is a call for re-negotiation of contracts and the formation of new contracts that address this.

What does all of this mean for oil contracts, the subject of this book?

Who knows, is the short answer. It would seem to suggest that the search for petroleum will continue, at least in the short term, with developing extraction technologies. Maybe this will produce a flurry of new oil contracts between companies and governments that address these new methods of extraction. But they might not.

The oldest contracts, from the days of Edwin Drake in Pennslyvania back in 1859, did not look terribly different, at the most fundamental level, than many of the contracts today. Is it time to race forward? Keep what we have got? A combination of the two?

We do not claim to know and it probably depends on who you're asking, but we do hope that this book enables you to engage in such a discussion and ask questions that could lead you to an answer. The contracts and laws in the petroleum sector are often reformed for various policy reasons and this book is designed to help the reader actively engage in this process.

3. The Life & Times of a Petroleum Project

Petroleum doesn't last forever. It is a non-renewable resource. This fundamentally drives the business decisions of companies, a key part of which is that most petroleum contracts are structured to contemplate the entire life span of a project, it's beginning, middle, and end. The key stages of a project's life (or "petroleum operations") are:

• explore to find it in the first place;
• develop the infrastructure to get it out;
• produce (and sell) the petroleum you've found;
• abandon when it runs out and clean up ("decommission")

Each of these stages is broken down and discussed in detail below.

Commonly found beneath the earth's surface are various types of rocks, water and salt, all of which react differently when hit with a sound wave. Large amounts of data are captured from this process and used to give an image of what lies beneath the earth's surface.

As computer technology has improved, seismic has been able to handle increasingly large quantities and complexity of data, though the cost of gathering and interpreting this incures increasing costs. This is why you will see in some contracts the type of seismic required (eg. 2D vs 3D), how many kilometers of seismic is to be gathered ("shot" in industry jargon) and specifically that it must be interpreted and the results provided to the host government.

Even with conducting seismic to help climb the confidence scale, one might need to drill several exploration wells to establish what is in fact below the earth's surface. One commonly used comparison to exploration drilling (particularly in the deep offshore) is trying to stick an extremely long straw in a drinking bottle from the top of a skyscraper and then drink from it. Of course, there are many areas where hydrocarbons are known to exist, though they might not be evenly distributed. In these cases seismic is still needed to increase the chances of 'hitting the target'.

Because most of us use fuel in our cars which we see as a liquid, many of us envision petroleum to be in lake-like pools below the earth's surface.  In fact, it is found in spaces or cracks within rock formations and needs various techniques to extract (relieve pressure, create pressure, etc).  One might picture a glass with a lot of crushed ice and trying to drink a milkshake from it.

While there is no standard amount of time one might conduct seismic studies and drill exploration wells in the world, these studies and drilling and the interpretation of the results even on a very rapid schedule takes months at the very lesat and more often around 2-4 years.

Appraising entails more drilling and seismic to asses what you have discovered, but to a greater degree of accuracy. It will lead to more detailed geological discovery while also involving assessment and reflection on how to build the necessary infrastructure to produce the petroleum you've found. You will want to know more about:

• the chemical composition of the various hydrocarbon deposits 
• the quantity of reserves in the area
• how to get these hydrocarbons out of the ground (if the discovery is found to be of commercial signficance)

• the business considerations of the company that has found the oil
• the local laws and regulations that determine the process of development

This can include decisions about how many wells to drill (yes, there can be more than one, there can be many!), what type of platform you will be building or whether to build a platform at all. Increasingly, offshore oil developments are using boat-like structures to extract petroleum, the Floating Production, Storage and Offloading units or "FPSOs" in short, or different varieties (eg. FPOs, or FPS's) which do only some of these functions.

The development phase is rarely less than several years. Engineering, community and business considerations, among others, all factor into the type and scale of infrastructure that will be used to extract the petroleum. This is the phase which requires the most amount of money in the life cycle (the most "capital intensive"). While exploration well drilling in the offshore might get into the hundreds of millions of dollars, complex, large-scale difficult environments for the extraction of petroleum can hit tens of billions!

It is important to note that significant amounts of petroleum will likely remain in the ground at this point. This may be because the financial system in place in the country makes continued production uneconomic and/or technologically there does not continue to be cost-effective means of producing petroleum. The environmental issues related to abandonment are discussed in the section: Environmental, Social and Health & Safety Issues, while project economics and their impact on production are discussed in the section: 'The Money'.

Other factors that may cause a contractor to halt or even indefinitely cease operations, may not, however, trigger the contractual obligation to decommision. These could include security concerns, social unrest or political instability. These 'force majeure' events would not terminate the contract, but could suspend the contractors obligation until operations were able to resume.

4. What is a Petroleum Contract?

Experts estimate that for a large natural resouce extraction project, there will be well over 100 contracts to build, operate, and finance it - all of which could fall under the broad category of 'petroleum contract'. There may also be well over a 100 parties involved, including:

• governments and their national oil companies (NOCs), e.g. Gazprom, Petronas
• international oil companies (IOCs), e.g. BP, Exxon, Chevron, CNOOC
• private banks and public lenders, e.g. JP Morgan, World Bank
• engineering firms, drilling companies & rig operators, e.g. Halliburton, Schlumberger, Technip
• transportation, refining and trading companies, e.g. Hess, Glencore, Trafigura, Koch Industries
• ...and many more

Among these many contracts, the most important is the one between the government and the IOC and it is this conract that will be addressed in this book. All of the other contracts must be consistent with and depend on this contract; these might be collectively referred to as "subsidiary", "auxillary" or "ancillary" contracts.

This contract is most commonly referred to by the industry as a "Host Government Contract" because it is a contract between a Government (on the behalf of the nation and its people) and an oil company or companies (that are being hosted). It is through this contract that the host government legally grants rights to oil companies to conduct "petroleum operations". This contract appears in countries throughout the world under many names:

• Petroleum Contract
• Exploration & Producting Agreement (E&P)
• Exploration & Exploitation Contract
• Concession
• License Agreement
• Petroleum Sharing Agreement (PSA)
• Production Sharing Contract (PSA)

A small minority of countries will not, however, follow this approach to petroleum extraction. They may, instead, manage most of extraction process themselves, therefore removing the need to partner with an IOC and the need for the Host Government Contract. Examples include; Saudi Arabia's National Oil Company Saudi Aramco and Mexico's Pemex.

We'll say it once and it will surely be said again: petroleum contracts are one key feature, living in a constellation or web of other laws and regulations above it and many other subcontracts and other ancillary contracts are below it. These will be referred to by the contract but will not be explicitly described, explained or re-written. 

This web of laws and regulations relating to petroleum within a particular country is known as a "petroleum regime". The petroleum regime can be best thought of as a hierarchy, starting with the constitution of the relevant country and ending with petroleum contract.

Next, there may be petroleum regulations, which are made in accordance with the petroleum law. As we move down the hierarchy from the constitution, to laws, to petroleum regulations, the rules relating to petroleum exploitation will become increasingly detailed and specific.

Competitive Bid: Given the value of petroleum today, many countries award contracts by holding a 'bid round'. Here, companies compete against each other by offering the best terms with regards to one or more defined variables to win the contract.

Ad hoc negotiations: Here an investor comes unsolicited and asks for a particular parcel of land and then negotiates a contract directly.

First-come, first-served: Alternatively, there might be an application system and the first company that applies and passes whatever regulatory hurdles the state may have, is then awarded the contract - with some negotiations over the terms of the contract usually involved.

The system for awarding contracts in a country (or different areas within that country) may depend on the current state of its petroleum sector. For example; Is there geological data already available? Is it a known petroleum producing area? Is there infrastructure already in place that could be used for this specific block? Hard to reach area?

Following negotiations, what was a government model contract will become a signed contract with a particular company or several companies. With the signing of the contract, the company or companies are legally awarded the exclusive right to explore and produce oil in the contract area.

• Concession: contractor owns the oil in the ground
• Production Sharing Contract: contractor owns a share of oil once it is out the ground
• Service Contract: contractor receives a fee for getting the oil

This would include oil if it was found below a private property owners land. Due to this historical origin, the concession similarly grants an area of land to a company, though typically only the sub-surface rights to the land, and therefore, if that company finds oil below the surface, the company owns that oil. Under the concession the contractor will also have the exclusive right to explore within the concession area.

How then, you may ask, does a country benefits from this form of contract? This usually occurs through taxes and royalties, though a state may also hold shares in the concession through its NOC in a Joint Venture with the contractor.

Indonesia can be credited with the innovation of Production Sharing Contracts in 1966. The Indonesian government decided, as a 'nationalistic' move, to move away from concessioning to contracting. This was done so that the state retained ownership of the petroleum produced and only gave the international company the right to explore and take ownership (or legally speaking "title") to it once the petroleum was out of the ground.

This innovation came about at the same time as many petroleum producing countries were gaining their independence and was part of the first wave of the so-called resource nationalism. Another key development during this time was the formation of OPEC (Organisation of Petroleum Exporting Countries) that led to further "re-balancing" of government-company relationships.

Under a Service Contract, title does not transfer at all. Unlike a PSC, where the oil company is entitled to a share of any petroleum produced, under a Service Contract, the oil company is just paid a fee.

In reality it is rare to find any contract that fits entirely into one of the descriptions given above and is more likely to take elements from each.

Those outside of this 'inner circle', even in other government departments, have historically found petroleum contracts shrouded in secrecy. As a result, the people that are interested, influenced, and affected by these industries, whether in producing or consuming countries often feel left out, in the dark, wondering where the money went or where the oil comes from and on what terms. And while a country's constitution is public (we hope!) and the laws are too (if sometimes hard to find), petroleum contracts are likely to be not easily accessible even if by law they should be.

The range of potential stakeholders is huge, and their concerns too numerous to list them here. While the majority of oil contracts today speak primarily about the financial and technical aspects of oil extraction, they are increasingly addressing concerns of stakeholders that are not directly parties to the contract but are deeply affected by it. This is further addressed in the section: Economic development.

Our great hope is that the rest of the book, which is devoted to the content of petroleum contracts, will help to empower people to read and understand these multi-billion dollar contracts that fuel our world.

5. Our Family of Contracts

We have selected a "bouquet" of petroleum contracts that are in the public domain to use for illustration purposes throughout the rest of the book. It's time to meet them!

6. The Anatomy of Petroleum Contracts

Generally speaking, contracts tend to follow the order in which things would happen in a petroleum project. After the introductions such as the list of terms to be used in the document they move onto exploration, followed by development and appraisal. Up until this point there is no pie to divvy up and so the clauses deal with operational management issues. Once commercial production begins, fiscal terms follow in the contract as in real life. After that come issues such as local content, dispute resolution and confidentiality, and other issues which may be more specific to each contract.

In the very back of the contract, it is common to see the Accounting Procedures for calculating cost oil in the annexes of a contract and various model forms of the ancillary contracts, like a Parent Company Guarantee or the Joint Operating Agreement. These are referred to as  "Annexes", "Appendices" or "Addenda" which are all additional documents that are referred to in the contract but for some reason or another, the parties thought the contract would flow better with it as a separate document or the need for the document came after the parties had agreed to the contract.  

To get a sense of how generic these contracts can be, let's look at the eight contracts that make up the "family of contracts" we quote from in this book. The table below shows the article numbers dealing with various early stages in the life-cycle of the project and the total number of articles in the main section of the agreement. Iraq doesn't have any clauses relating to exploration because they are dealing with sizable discovered fields.

It also helps to know then that this term is now an approved or reserved term which will appear either in capitals ("Effective Date") or sometimes block capitals ("EFFECTIVE DATE") throughout the contract.

To answer any question, you'll want to start at the table of contents (hope that there is one, they are your best friend - otherwise, the chase has just become that much more difficult) and see which heading would seem likely to answer your question.  In our case, "Term of Contract" (Article 3) seems the most promising. Flipping to Article 3, we find the following:

One part of our question is quite easy: the term of the contract is 20 years.  

But when does it start?  3.1 says "on the Effective Date".  Because the term is capitalized, we have to go to the definitions and see what it says.  

This defintion shoots us to Article 39:

Not a very straightforward answer, but an answer nonetheless.  Upon these "trigger events" (whenever those may occur) that point will be when the contract will last for 20 years.  

Except for the exceptions.  3.2 tells us that the term is extendable pursuant to Article 31.  You'll want to flip back to the table of contents to see what this article covers, which is "Force Majeure"   which, in summary, is a concept found in many contracts (not just petroleum) that allows the suspension of a contract while so-called unforeseen events or "acts of God" like hurricanes or acts of war allow the contract to be suspended until the event has resolved.  So, this is one way in which the contract might be extended.   But the last phrase of 3.2, "or elsewhere in this Contract" is where things get really ugly: this clause literally shoots you to the entire contract to hunt and see where else the contract might be extended.  Depending on just how precise you need to be with your answer, your task may have just gotten a good bit longer.

If you're staying fairly general, 3.3 tells you that there could be a 5 year extension if the Contractor requests it from the ROC, which you would need to go to the definitions to find out what this is.  

We have our general answer.  The contractor will need to go to the State to get 5 more years for a possible total of 25 years.

So in order to understand this short article, we have now been referred to at least 4 other  other locations in the document for a fairly general answer and we would need to review the entire document for a specific answer!  

This is quite normal. Petroleum contracts are interwoven in this way. You could spend quite a long time following the trail of an issue from one clause to another related clause and it is only with the passage of time that you begin to develop a sense of when it makes sense, for your immediate purpose, to follow the trail and when it is time to stop.

Finally, even if you are only interested in one agreement, it is worth spending the time to read several others to begin to get a sense for what is common in petroleum contracts and what might be of more specific interest in the one you are looking at. The extra confidence and understanding you gain will more than repay the time and effort.

7. The Stars of the Show

If the petroleum contract is the script, the stars of the show are those entities that sign the contract and agree to be bound by its term and conditions. They are what we call the "parties" to the contract. The parties are usually the host government line ministry or its state/ national oil company (NOC) on the one hand, and an IOC or a group of IOCs, on the other. IOCs may be referred to as the contractor, the licensee or the concessionaire depending upon the type of the petroleum contract signed. Frequently more than one IOC is a party to the petroleum contract. Such group of IOCs is called a "consortium". Each of the companies are an individual party to the contract, but are treated as one entity and are collectively called the "contractor", the "licensee" or the "concessionaire". From the state's perspective, if the IOCs together fail to fulfill their obligations then they are all at fault. In legal language the IOCs are said to have "joint and several liability" for the performance of the contractor's obligations under the contract.

For example, BP PLC as the parent company sits at the top of the BP group of companies. BP PLC is the entity that people have in mind when BP is referred to in the media. BP's interests in various countries are held by affiliate companies such as BP Exploration Angola, BP Egypt Company, BP Energy Brazil and so on. These affiliate companies will be the parties to the petroleum contracts in the relevant countries, not BP the parent company.

Often the only asset of this affiliate company is the field as determined in the petroleum contract to which it is a party. This exposes the country, and therefore the other parties to the contract, to a lot of risk. This is because there are no available financial resources on this company's balance sheet, only oil in the ground to cover any costs. In order to mitigate this risk the state will often require a company within the BP family and with more assets and financial strength (a "bigger balance sheet") to guarantee that the affiliate company will perform its obligations. If the affiliate fails to perform its financial obligations under the petroleum contract the state can require the parent company to step in to fulfill its affiliate's obligations.

This grant of right is the main purpose of the petroleum contract. All other rights and obligations are subordinate to it. The clause gives the contractor the right to conduct the components of Petroleum Operations, which are: exploration, appraisal, development, extraction, production, stabilisation, treatment, stimulation, injection, gathering, storage, building rail or roads for loading facilities, building connecting entry point to rail network or to existing pipelines, handling, lifting, transporting petroleum to the delivery point and marketing of petroleum from, and abandonment operations with respect to a contract area.

This grant of rights may be mirrored by a similar statement of obligations. An example is given below:

This clause sets out an obligation on the concessionaire to make investments, bear all costs, and provide all necessary equipments, personnel, technology required for the conducting of petroleum operations.

Contracts also include provisions on rights and obligations of host governments. After all, they are a party to the contract, too. An example showing the rights of the host government is shown below:

The same contract also puts a number of obligations on the host government, such as for them to grant all necessary permits and licenses for conducting petroleum operations and open bank accounts, provide entry and work permits for employees, provide permits for importing equipment and materials, provide access to pipelines, prevent hindering the conducting of operations, etc.

The contracts will lay out a decision making process that will be used throughout the life of the contract . This enables both the government and the contractor to fulfill their respective obligations. This is essentially a series of proposals (by the contractor) and approvals (by the state) as events unfold.

Three basic mechanisms are used:

• Yearly work programs
• Plans for the petroleum project phase
• Committees make decisions and the Operator carries them out

The chapters that follow explain all of these in much more detail. The next chapter describes the decisions to be made in each phase of the petroleum project. The next describes who does commitee decision making process. The last describes how the operator carries these out.

This is a key theme that has come up a number of times in this book: contracts reflect changing times in the bargaining power and the desires of countries. These profoundly important and often deeply political issues of global magnitude manifest themselves in what might otherwise look like a mundane paperwork generating clause in a petroleum contract. In fact, these clauses are part of the fundamental re-shifting in the balance of power--or at least the attempt to. Some of these dynamics are described in the chapters that follow to help give context to these contract clauses.

Currently, there is tension between states wishing to assert their sovereignty over natural resources and companies wishing to maintain control over the operations. The result, then, is that most contracts signed today represent a compromise. They specify joint management structures and procedures. From the state's point of view, one of the advantages of such joint decision-making mechanisms is to increase its management control over petroleum operations by the host government. From the company's view, this management control can decrease efficiency, increase costs and delay profits.  But it can also facilitate better relationships with the state over time.

But just because a state has a NOC or has set up a joint management committee, a more robust and equal decision making process is not guaranteed. Countries without NOCs or management committees can exercise management control and have discussions with IOCs and be just as effective at shaping their petroleum sector by having the skills, knowledge and laws to effect these goals. This section does not deal with these systems in much detail since the focus is on what contracts do say, and many of them spend a good deal of their text on these issues.

8. The Roles They Play

What IOCs must do, when, where, how, and at what cost, constitute one of the the fundamental areas in petroleum contracts. To address these issues, petroleum contracts include important clauses related to:

• the definition of an area where exploration and production will be conducted
• the surrendering of unused parts of such area back to the government
• work and financial committments during each phases of petroleum operations
• evaluation of a petroleum finding and development of the field
• annual work programmes and budgets
• data and reports to be provided to the government to inform it and facilitate it in the decision-making process
• ...and many more

Another important reason is that the determination of size may affect the likelihood that the IOC will make a commercial discovery within the specified area. The smaller the size of the contract area, the higher the chance that it will be on the same geological oil field, or reservoir, as another contract area. This can lead to complications, as the two parties then have to work together, usually through creating a unitisation agreement, to extract the petroleum in the most efficient way.

Some countries use standard size of acreage in awarding contracts (e.g. US, UK, Norway, Brazil, etc.). Most of these countries usually use a gridding system based on geographical minutes. This system allows the contract (concession) area to be accurately defined by reference to coordinates as defined by the Greenwich Meridian Line. Unlike the countries with predetermined size of contract area/acreage, the size of the contract area is subject to negotiations and agreement in other countries. For instance, the Trinidad and Tobago Deep Onshore Model Production Sharing Contract of 2005 serves an example for the latter option. The clause 3 of the model contract ("Contract Area") stipulates the following general characteristics:  

Under this clause, the size and map of the Contract Area is negotiated and agreed between the parties and attached to the contract. In addition to such clauses, the petroleum contracts tend to explicitly exclude the rights of oil companies to any other natural resources or aquatic resources in the contract area except for the right to explore, develop and produce hydrocarbons.

The size of the contract area may impact what happens in it. The larger the contract area is, the more likely there will be many activities going on it.

The first part, the exploration phase is a bit unique. This is the one where the parties will specify in some detail the work programs to be carried out in each exploration year. This is because exploration activities are the only ones that can be planned and predicted to a certain degree of accuracy at the time of negotiating and signing the agreement- as mentioned earlier, at the point of signing the contract neither party can be sure that anything further than the initial exploration phase will actually happen.

In the diagram above, you will see that the most explanation is given for the exploration phase. That is because there is often more written about it than any other phase in the contract itself.

However, the yearly activities to be conducted later, such as phases of appraisal, development, production and abandonment will not be specifically planned, except at a very general level, in the contracts. Why? Because you do not know if you'll ever get past the exploration phase, but you're crossing your fingers all the same.

For the appraisal phase, questions such as; "What is the most efficient and sensible approach?" and "How many appraisal wells need to be drilled?" cannot be answered when the contract is signed since we do not yet know whether there will be anything to appraise at all. Contract details concerning the development or later phases are even more speculative; the parties couldn't possibly know how many wells, platforms, and what type would be needed without knowing what is in the ground. But they do create processes for what they hope will result: oil production.

• Time limits for exploration
• Relinquishment requirements
• Minimum work and expenditure obligations
• Approval of annual exploration work programs and work program budgets
• Progressive area fees or rentals (discussed in the fiscal section of this book)
• Supervision of exploration work by the government or NOC.

The exploration period normally starts from the date when the contract become binding on the parties and continues for a number of years, for example, three (3) or more years with the possibility of further extension for an additional period of 1 to 3 years. The length of the initial exploration period should depend on the size and nature of the contract area. The government shall be weary that the length of the term should be sufficient to carry out an efficient and adequate exploration program, but not so long as to permit the contractor to be inactive.

In countries with rich geological prospectivity and previous petroleum discoveries, the situation is different as far as the scope of work commitments in the exploration stage is concerned. The core of most work programmes is the obligation to "shoot", or record, a specific number of line kilometres of seismic and to drill exploration or wildcat wells. The determination of work programme or expenditure obligation is usually subject to intense negotiations as this phase constitutes major risks for oil companies before making a commercial discovery. The specification of these terms depends on the circumstances of a particular case and petroleum prospectivity of the country. The minimum exploration work program and expenditure and drilling obligations are key points in petroleum contracts since a failure in exploration terminates the contract for the oil company and it is not compensated for the reconnaissance, drilling and appraisal costs and hence such costs constitute a sunk cost. Typically, IOCs insist on lesser work program and flexible expenditure obligation with carry forward provision.

The Equatorial Guinea Model Production Sharing Agreement may serve an example for the scope of work obligations to be carried out by the oil company at the exploration phase. Pursuant to Article 3 of this Anogla contract ("Exploration Work Obligations") shall do following minimum work program at its own risk and cost:

Under the outlined model, the contractor shall not only acquire and interpret certain seismic required to drill a number of exploration wells and invest the agreed amount of required financial commitments.Such financial commitments are usually equivalent in value to the estimated costs of the minimum work programs which are stipulated in the agreement for each year. In the event of the stipulation of the defined amount of financial commitment, the contractor must satisfy both the minimum work commitment and the minimum financial commitment for a particular year. Thus, if the minimum financial commitment has been met but the minimum work program has not been completed, the contractor must nevertheless complete that work program. Conversely, if the work program is completed but the financial commitment has not been fully expended, the contractor will be required to conduct additional exploration activities up to the balance of the financial commitment.

At the end of the second Exploration Phase, the Contractor shall retain only Development Areas and Discovery Areas."

Such provisions prevent petroleum companies from “locking up” large contract areas which they do not use for exploration work.

In addition to mandatory relinquishment clauses, petroleum contracts may also include voluntary relinquishment mechanisms whereas the oil company surrenders a part of the contract area back to the government even though the contract does not require it to do so. Under voluntary mechanism, the contractor will usually have the opportunity to surrender voluntarily any or all of the area at any time subject only to fulfilling the work commitments and serving an advance notice to the government.

There is a considerable variation in relinquishment obligations in world petroleum contracts. The time periods for relinquishment should be viewed in the context of the size of the contract area, the overall length of the exploration period and the nature of the exploration area itself. Generally, such obligations are more strict in petroleum producing countries with proven reserves than in countries with a lower potential for oil production. The areas to be relinquished may constitute between 50% and 75% of the original contract area. Relinquishment is usually made in two or three steps, say, 25% each two year.

Petroleum contracts usually provide that in the event of a petroleum finding petroleum company shall notify the ministry or NOC of such a discovery and its commerciality within certain period of time. In addition, petroleum company has to submit all supporting information and data analysis. The Production Sharing Contract between The Government of the United Republic of Tanzania, and (hereinafter referred to as the “Government”), The Tanzania Petroleum Development Corporation and ABC Oil Company as of 2004 provides for the following mechanism (Article 8: Discovery and Development) in the event where a discovery is made by the contractor:

After a discovery found to be commercial by the petroleum company as the contractor, in development stage, as in the case of exploration, the objectives of the oil company and host government regarding the timeline and the scale of investments needed to develop a field can differ. Host governments usually have an interest in rapid development of any field which is discovered. Given the limited duration of the contract, the oil company also has such an interest. However, if full freedom to decide whether to develop a particular discovery is left entirely to the oil company, there are potential risks that the petroleum company could decline to invest in development immediately because of its other priority projects in terms of its world-wide operations. Therefore, in order to mitigate such potential risk the contracts usually tend to put some time limit and other requirements (immediate supply of information to the government, formal approval, etc).

In the event the petroleum company declares a finding to be commercial, petroleum contracts usually provide that it petroleum company as contractor must prepare and submit to the Ministry or Joint Management for approval its plan for the development and production of petroleum from the contract area ("Field Development Plan" or "Development and Production Plan"or "Exploitation Plan"). This Plan is a long range plan for the efficient and prompt development and production of petroleum from the contract area. The Azerbaijani PSA may serve an example for such a mechanism. Under this PSA (Article 4.4.), the Contractor within 30 days days following completion of the minimum work programme the petroleum must prepare and submit to the Steering Committee for approval its plan for the development and production of petroleum from the contract area, which must include the following components:

In light of the above clause, the Field Development Plan include not only operational and infrastructure issues, but also local content and ESIA issues which are hugely important for host governments. The approval mechanism of development programmes in a comparative perspective is discussed in the next section entitled "Contract Governance".

In light of the importance of exploration and development for host governments, one of the important issue is the consequence if petroleum company fails to carry out the work commitments during the exploration and development. To counter such risks, petroleum contracts may stipulate that in the event the contractor fails to carry out the exploration work programme and development programme within a certain period of time, except in case of force major, the Ministry or NOC usually has the right to unilaterally terminate the contract and the costs incurred during the exploration, development and bonuses are not cost recoverable.

If at the end of the initial exploration period (including any extension period) no commercial discovery has been made, the petroleum contract automatically terminates. As a rule, the development and production period begins from the date of the notice of discovery and its commerciality submitted by the oil company to the government or NOC and continues for a number of years, for example, 25-30 years. At the end of the contract, the IOCs transfer all petroleum operations and assets back to the host government or NOC, as the case may be.  Petroleum contracts should make sure that there is enough security of tenure, meaning the oil company has an automatic development and production rights once a commercial discovery is made at the exploration phase.

No matter what this document is called, it should describe, item by item, the petroleum operations to be carried out during a calendar year, for example, how many wells (appraisal, development and productions wells, as the case may be) will be drilled, pipelines, facilities to be constructed, procurement plans, etc. Contracts usually require the submission of work programmes to be accompanied with Budgets, meaning estimates of expenditures for carrying out in an annual work programme. The Angola Model Production Sharing Contract for Deep Water Blocks between SONANGOL and International Companies may serve an example for this particular case (Article 19 Development and Production Work Plans and Budgest):

As will be fully discussed in the next chapters an annual work programmes and budgets will generally be approved by the joint management committee or the relevant ministry, as the case may be. A control on annual work programmes and budgets allows host governments to supervise the implementation of a general Development Programme and/or Production Programme and the costs associated with such works.

9. Joint Management

We have established that a common mechanism to manage activities within the petroleum contract is to create a committee, with representatives from both state (government or National Oil Company) and the International Oil Companies (IOCs). This allows both sides, in theory, to have a say in decisions that need to be made - a happy compromise.

Different terms describing this concept include:

• Joint Management Committee - Iraq, Indonesia, Bangladesh, China, Ghana
• Steering Committee - Azerbaijan
• Technical Consultative Committee - Gabon

Despite the varying names, the general functions of such a committee remain similar around the world, and responsibilities assigned to them can be fairly broad, as illustrated below.

If you have been on a committee of any sort, you will have an idea of what the general nature of the committees used in the petroleum sector. You have meetings, take notes, approve the notes, then execute the decisions made at the meeting. There are procedures for holding emergency votes and meetings. Budgets are discussed and approved.  

Under this Iraqi clause, the joint committee not only supervises operations and finances but also oversees personnel and training issues, local goods and services and subcontracts. This isn't always the same, however - in other clauses, the scope of powers of joint management committees may be limited to the technical aspects of getting oil out of the ground.

Decisions of joint management committees may require the unanimous or majority vote of the parties on certain issues. In the event there is no majority consensus of the parties in such a vote, there may arise a deadlock, with an even number of votes on each side.

The Libyan contract for example specifies a committee of four, with two from the companies and two from the government. Ghana's contract with Tullow specifies eight members, four and four. But neither contract actually specifies what to do in the case of a tie.

So what happens if "the Parties" don't reach an agreement? This contract does not specify.

The Kurdistan Regional Government's contract with Talisman is even more complex. The Management Committee has four members, two from each side, one of the two from the government side is the chairman of the committee, and in the event of deadlock on any particular decision,

But, although this clause taken on its own appears as though it does address this issue, not so fast!

The next clause, Article 8.4, says Article 8.3 does not apply in the exploration period, and that if no agreement is reached "then the proposal made by the contractor shall be deemed adopted by the management committee."

And if that weren't complicated enough, Article 8.5 then lists eleven exceptions to the rule that the Chairman has a tie-breaking vote, including provisions as vague as "any matter having a material adverse effect on Petroleum Operations".

So actually, the issue isn't solved at all, and is left for parties to battle out themselves as and when they come to it. In reality there are a number of ways out of deadlock. One is referring the matter to the senior management of the parties. Another way is to appoint an independent expert or arbitration through mechanisms that are established separately elsewhere in the contract.

One might reasonably ask: why don't the parties just specify all of this at the outset? Government gets tie-breaking vote or there has to be unanimity? There is not one answer that would hold for all countries the world over, but as a general matter, it goes back to the "happy compromise" raised at the very outset of this chapter. IOCs want maximum flexibility and control over the operations and have the technical and financial capacity to carry them out; while governments also want control and to influence the operations, but they do not have the technical and financial resources to do so themselves. --Deadlock and dispute resolution is when the otherwise happy compromise "hits a rough patch".

As you might have been able to tell from this, there is an inherent ambiguity in the ongoing relationships between governments and international oil companies; this also corroborates what many lawyers and industry professionals say about negotiation being permanent in the oil industry. Even though you can sign and agree on a contract, there are many possible events for which the decision-making process is unclear if the parties have serious disagreement. Partly this is because, as written above, at the time of writing and negotiating the contract, it's impossible to know what might or might not happen during the contract's lifespan.

Some common hot issues for management committees are, unsurprisingly, levels of investment and levels of production and issues relating to domestic. Companies generally want to invest as little as possible for any given level of production as, unsurprisingly, their aim is profit maximisation.

10. The Operator

The operator is the lead actor to the joint management committee's director - the one who learns the lines, puts the work in, and shows up, every night of the performance. The one that does all of the day to day running around, and the one who carries out those "petroleum operations" we keep mentioning. After all of the decision-making at the petroleum phase level and the yearly level has been made, someone must actually implement those decisions on a day-to-day basis. Enter the stage: The Operator.

Broadly speaking, oil companies have begun to group together in consortia to bid for and manage large production, rather than going it alone. Among these companies, there will be one who is approved by the host government to be the operator.

The official terms outlining this role may differ slightly from one contract to another (Operatorship, Joint Operating Companies, The Role of Operator) but the concept is the same. In the following example, the operator is discussed in the definitions at the beginning of the contract.

Whereas in Azerbaijan, in the example given below, a Joint Operating Company was established.

In Iraq's 2009 service agreements, the JOC-type structure specified was a Field Operating Division, a unit which was detached from an existing parent company owned by the Iraqi state. Under this structure, ultimate authority lies with the Iraqi state, but lower level decisions are delegated downwards to the Management Committee and then to the approved operator, the Field Operating Division.

By being in the Joint Operating Company, Azerbaijan is able to gain expertise as it participates in the process of the operator proposing and the committee discussing how it will carry out its wide range of roles. Other clauses (Article 6) specify target levels for the ratio of Azerbaijanis who are to work in the operating company at different stages in the project, rising to 90% in professional positions after five years of full operations in a field. This gives Azeris not just the opportunity to learn management and decision-making but also the carrying out of operations.

In Iraq's 2009 service agreements, the JOC-type structure specified was a Field Operating Division, a unit which was detached from an existing parent company owned by the Iraqi state. Under this structure, ultimate authority lies with the Iraqi state, but lower level decisions are delegated downwards to the Management Committee and then to the approved operator, the Field Operating Division.

Aspects addressed in this data monitoring are not just (directly) about money, such as accounting and auditing. Petroleum extraction is incredibly data intensive, and this costs money, so the contracts may also require the IOCs to save and keep unused cores and samples from wells and make them available, as well as all data resulting from petroleum operations, including geological, geophysical, engineering, well logs and production data, as well as reports, analyses, interpretations, maps, and evaluations.

Some contracts supply a lot of detail about what exactly the company has to provide- for example, in the “Shah Deniz PSA” it is written:

Here, the term "contractor" is used (as noted above), but it is the operator who is tasked with carrying out these activities on behalf of the IOCs.

These clauses also specify that representatives of SOCAR only have to give three days notice at any time to carry out an inspection of "Petroleum Operations", which could either be company offices or in the field; this, in effect, is a way of keeping the operator on their toes.

One word of warning! Contracts will often use the more generic term "contractor" when it is in fact the operator who will end up generating this work on behalf of all of the joint venture partners. Just because the contract says that the Contractor will carry out certain activities as the clause above does, it does not mean that all of the companies that comprise the contractor will in fact carry them out. The Operator will generally do these. However, if the Operator does not, for some reason, carry out the obligations, all of the other companies will be responsible for fulfilling them. This may mean finding a new operator or appointing a new operator from among the group, though these situations are relatively uncommon.

11. Maths, Myths, and Mentally Warming Up

Let's face it: most of us do not do mathematics every day. With calculators, computers, and economists around us, why do the maths ourselves?  For many, the last time we contemplated percentages and equations and the like may have been high school. But numbers are unavoidable in this section on the fiscal regime of petroleum contracts, and actually it turns out they're not too bad.

The complexity of the numbers in modern contracts comes from complex political and economic relations within the oil industry. The rise of resource nationalism, the increasing number of state-owned oil companies, the volatility of oil prices, means that governments try to capture as big a share of the money as possible while still encouraging investors to come in and spend their own money on projects that might fail through no fault of their own. These factors, amongst others, contribute to complex fiscal terms.

This section starts by building from the ground up, running through the range of fiscal tools that are in current use and which together are used to build a fiscal regime. Next, in Fiscal Strategies and Solutions, we examine such regimes in their entirety and how they address particular goals a government might have in developing its petroleum industry - or not. Then we look at how governments and their citizens can assess how they are doing in fiscal and financial terms and find that despite the availability of statistics it is not easily reducible to one figure. Finally, we explore how oil is priced, another aspect which is not as straightforward as it might sound .

As people rightly demand more information about how natural resources are being managed on their behalf, there is a tendency to grab whatever snippets of information are around and take it for the whole picture. Unfortunately, There is no one single number that can explain the whole financial situation.

Lastly, there’s often confusion about the difference between revenues and profits. To clarify: a project generates income, for example through the sale of crude. A project's income is sometimes also referred to as revenues. Usually, there are multiple ways of receiving revenues, or multiple 'revenue streams', which comes from, for example, taxes and royalties as well as direct profits.

Revenues include money spent - which are considered as negative revenues - as well as money coming in, positive revenues. Profits on the other hand, are calculated from the total project income minus the project costs -

To add to the revenue confusion, the government receives additional revenues from the project in the form of taxes and royalties. Costs are the expenditures on equipment, salaries, etc incurred throughout the project. Profit is what’s left over if costs incurred and taxes are deducted from the project's income.

12. The Fiscal Toolkit

States and International Oil Companies (IOCs) have many options at their disposal to share the value of oil and gas projects. Let's call these 'tools' that the state or IOC can use to determine a fiscal payment that is made to either side. Together, these tools make up a 'toolkit' that can be used to design the fiscal regime - the rules for managing money- in a petroleum contract.

The basic concept here is that the state and the IOC need to share the 'divisible income'. This is the term used to describe the amount of money that remains after the lifetime revenues of a petroleum project are reduced by the lifetime costs of the project.

The share of the divisible income that goes to the state is called 'government take'. The remainder that goes to the IOC is called 'investor take' or 'contractor take'.

This chapter will describe each of the fiscal tools that are commonly used in petroleum contracts. The next chapter will then describe how states select some of these tools to create a petroleum fiscal regime that shares the divisible income.

Fiscal tools in these three types of contracts include:

• signature bonus
• production bonus
• rental
• royalty
• corporate income tax
• profit share
• state participation
• other profit-based taxes
• other general taxes (such as import duty, sales tax, property tax, excise tax, withholding tax)

So, with this contract type, the government retains the overall revenue, minus what they pay to the companies; the service contract simply defines terms and conditions for certain services that the IOC carries out, for which it is paid. Governments naturally like the ideology behind the service agreement model as it reinforces, politically and financially, a high degree of control and complete ownership of the resource. Iraq's service agreements of 2009-11, are an example of such a risk service agreement.

There is only one type of fiscal tool for risk service contracts, and that is the 'service fee' which may be defined differently per contract.

• Signature Bonus - a payment made to the government at the time that the petroleum contract is granted.

The signature bonus is frequently a deciding factor in determining winning bids, when companies want to be awarded a contract. It may be negotiated, or set by legislation.

It can vary from as little as a few thousand dollars up to many millions. Signature bonuses tend to be small for fields where geological data is relatively poor or non-existent, and so exploration cost is high. Conversely, signature bonuses are high where there is good geological data and thus a higher chance that exploration will be successful.

• Production Bonus - a payment made at a certain point in time during the life of the petroleum contract.

A production bonus may occur at the time that a commercial discovery is declared, at the time that petroleum production begins, at a defined production rate, or at a defined quantity of cumulative production. An example of payable production bonuses is shown below.

The production bonus provides to the government a fixed amount of revenue at a certain point in time. Also, this bonus tends to increase as the amount of production increases.

• Rental - a fixed payment made on an annual basis at the beginning of the calendar year or contract year.

A rental may take on different forms- it could be a fixed amount for the contract, or fixed amount per square kilometre of operations land, or a negotiated amount. It may be payable during the exploration phase, the production phase or both.

The rental serves a number of purposes. It provides to the government a guaranteed annual income of a known amount, which helps in budget planning, irrespective of changing oil prices. The government can calculate the expected amount of rental payments it will receive based on the number of petroleum contracts it has granted and the area that they cover. This contributes to the government's administrative costs of running the petroleum operation. It also creates a mild incentive for the IOC to voluntarily relinquish any area where it does not intend to conduct exploration activity, permitting the government to offer that area to other companies

Rentals are used globally in concessions, production sharing contracts and participation agreements. IOCs are often also required to pay additional amounts for access to the surface for conducting petroleum operations- sometimes to the private occupiers of the surface, and sometimes to the state.

• Royalty - a payment made by reference to the amount and value of petroleum produced

A royalty is a traditional feature of many petroleum contracts. A royalty is usually calculated without deduction of any costs. There are various forms of calculating royalty, as outlined below. 

A royalty takes no account of the costs of exploring, developing or producing oil & gas. Consequently, depending on what those costs are, a fixed royalty of say, 12.5%, could easily reduce company profits by 25% or more. Therefore, if a fixed royalty is too high, a producer may abandon the project even though oil & gas can still be produced.

Fixed royalty rates may be common, but increasingly states are creating sliding scale royalties that vary the royalty rate based on other criteria. A sliding scale royalty rate may be created using the following:

• level of field production
• level of well production
• location
• cumulative production
• production rate and price
• R factor
• internal rate of return
• other criteria such as water depth, oil gravity, or elapsed time 

The concept of a sliding scale is also used in relation to profit shares which are discussed below. The following description of sliding scales will therefore be applicable to that fiscal tool as well.

• production rate is higher
• prices are higher
• costs are lower
• costs have been recovered

Therefore, a petroleum project is likely to be able to bear a higher royalty in these circumstances. By using these factors as an analogue of profitability, it is possible to create a fiscal system that is designed to generate a higher rate of government take as a project becomes more profitable. This can happen without measuring the actual profitability of a project, which is an administratively difficult or expensive process.

An increasingly common method for creating a sliding scale that is designed to address profitability is the use of what is referred to as the 'R factor'. 'R' stands for 'ratio', so an R factor is a sliding scale that employs a ratio of two numbers to determine a rate. In the oil & gas industry, the most common R factor is a ratio of cumulative revenues divided by cumulative costs, as follows:

R = Cumulative Project Revenues

Cumulative Project Costs

• R is less than one when a petroleum contract first begins. and the IOC is incurring costs but does not yet have production - so, when project costs are greater than project revenues
• R = 1 once project revenues equal project costs (a time which is commonly referred to as 'payout')
• R is more than one when project revenues are greater than project costs, in the production phase

An R factor is then used to create a sliding scale royalty as follows (using Peru as an example):

Therefore, a royalty rate that began at 15% for initial production (when the R factor is less than one, because costs are greater than revenues) would jump by steps to 35% when the IOC has received out of production revenue an amount equal to twice its costs, when they are in the production phase.

• the wellhead (common in North America)
• the field measurement point (common outside North America)
• block boundary
• export terminal

If the point of royalty determination is further along in the value chain from the point at which the sale of production occurs (as is commonly the case), then it is necessary to calculate the value at the royalty determination point. Typically this is done by deducting the cost to transport and process oil & gas from the royalty determination point to the point of sale. This can be more difficult than it sounds, because often these costs are not arm's length costs paid to a third party. Where the IOC owns the transportation and processing facilities, it is necessary to ensure that these costs are not excessive and do not include a profit component beyond a reasonable return on invested capital goods.

In the example above, a 10% royalty would be $8.90 if determined at the export terminal, $8.50 at the field terminal and $8.30 at the wellhead. In similar situations for natural gas, the deductions leading to the value at the wellhead can be so significant that the royalty is significantly reduced.

• oil & gas vented or flared (where permitted)
• oil & gas reinjected in the reservoir
• oil & gas used in field operations
• oil & gas lost (so long as losses did not result from negligent conduct)

• Corporate Income Tax - a tax on the net income (or profit) generated by a corporation from the activities that it conducts
  

It is beyond the scope of this book to discuss the concepts of corporate income taxation. However, there are a number of attributes of corporate income taxation that are relevant to understanding the overall fiscal features of a petroleum contract.

Most petroleum fiscal regimes include corporate income tax as one of its features. The underlying concept is that IOCs, like any other corporate citizen, should pay income tax (in addition to other payments as discussed above, because petroleum is a state owned resource). Even in Ireland, whose fiscal regime for petroleum operations is comprised solely of its corporate income tax, IOCs are charged a 25% corporate income tax whereas other companies in Ireland pay only 20%.

Corporate tax rates applicable to petroleum activities vary widely around the world, from a low of zero in some tax haven states to a high of 85% for certain operations in Nigeria. However, most states impose a corporate tax in the range of 25% to 35%. 

It is important to understand that corporate taxation is a different type of fiscal feature compared to royalties, profit shares and other tools. Corporate income tax is determined at the level of the corporation, where other fiscal tools determine the amount payable at the level of the well, the field or the petroleum contract. Consequently, corporate income tax will include features like deductions for depreciation and other features of the corporate income tax regime. The resulting tax calculation can therefore yield very different results than a royalty; a 12.5% royalty is very different than a 12.5% rate of tax.

Some states create special rules for assessing corporate tax on oil & gas operations.

This concept is sometimes referred to as 'ring fencing'; the activities of the IOC are taxed as though there is a ring fence around the defined area.

Ring fencing allows the tax regime to look only at the activities within the ring fence, so that other gains, losses or costs outside the ring fence are excluded. We will see this concept used in other fiscal tools as well. The converse of ring fencing is called 'consolidation', where activities across multiple contract areas are treated on a combined basis.

• cost oil, which is the share of production that the IOC will receive for recovery of the costs it has incurred, which is subject to a maximum amount (the 'cost oil limit'); and 
• profit oil, which is the share of production remaining after cost oil has been delivered to the IOC.

If the resulting production includes gas, there will also be a cost gas limit and a profit gas share, which often is a different limit and share owing to the economics of gas development.

The following diagram is a visual representation of how the total production is allocated between the IOC and the state in a production sharing contract:

Now let's examine the different ways that profit oil/gas shares are determined, and cost oil/gas limits are established. For ease of reading, in this section we will speak only of 'profit oil' and 'cost oil'; the same concepts apply equally to gas.

This simple formula has changed a number of times since first used in Indonesia, and many new concepts have been created to share profit oil and determine the cost oil limit. Many states still use fixed profit oil shares, such as:

• 40% in Timor Leste
• 50% in the Thailand-Malaysia joint development zone
• 60% in the Philippines

• level of field production
• cumulative production
• combination of field and cumulative production
• R factor
• combination of R factor and field production
• internal rate of return
• cost limit

An R factor can be used to create a sliding scale profit share, as shown below (using Azerbaijan as an example):

R-FACTOR PROFIT OIL TO GOVERNMENT

The higher the cost oil limit, the better for the IOC, because it will recover its investment more quickly. Fast recovery of investment is more attractive to the IOC and meets government objective of attracting foreign investment.

Timor Leste and Guatemala have no cost limit and no cost depreciation rules, so in theory the IOC could receive 100% of production until costs are recovered. But both of these states add a royalty that is payable in cash or in kind, thereby ensuring a minimum production share to the state.

• State Participation - as a fiscal tool refers to cases where the state participates in the petroleum contract as a co-contractor with the IOC.
  

States sometimes participate directly in oil & gas activities, typically through a state or national oil company (often referred to as a "NOC"). In effect, the state co-invests in the exploration, development and production activities together with the IOC. If the state participates in this way it is a party to the petroleum contract in two capacities: as the owner of the oil and gas resource and grantor of rights under the petroleum contract and as an investor.

There are three important questions that affect the role of state participation as a fiscal tool:

Question 1: how large a percentage of the project will the state oil company have
Question 2: when does the state oil company begin to participate, and
Question 3: what costs of the project will the NOC bear

Answer 1: most states establish a fixed percentage for state oil company participation, which varies from a low of 5% (as in Belize) or 10% (as in Indonesia), to a high of 50% (as in Brunei and Tunisia) to 60% (as in Abu Dhabi).

Answer 2: when the state oil company participation begins,this can be from the start of the contract. However, the challenge for a state oil company is often the ability to pay its share of the costs, and the willingness to assume the exploration risk that the activity may not be successful. It is rarely a good idea for a state to take a lot of exploration risk, particularly if it is not a wealthy state. This challenge can be addressed in two ways. One way is to give the state oil company an option to participate in the project, and triggering that option at a point in time when some or all of the exploration risk is eliminated. Therefore, many state participation rights give to the state oil company an option to participate up to its designated share at the point of declaration of commerciality, or upon approval of the development plan, for example.

The second way of managing the challenge of the state's ability to pay its share of costs is addressed by answering the third question, as to what costs will the state oil company bear.

Answer 3: There are three alternative answer to this question which define the type of state participation. These are:

• 'full equity' participation (as in Norway) in which the state oil company bears its share of all costs in full;
• 'partial carried interest' in which the IOC bears (or "carries") all of the costs incurred prior to the state oil company's election to participate but, following the election to participate, there is a repayment of some or all of the state oil company's share of the costs incurred before the election to participate (as in Indonesia or Uganda). The repayment may be, under a Production Sharing Contract, for example, by way of the IOC receiving part of the state oil company's share of production. This is also known as a "soft" carry; and
• 'full carried interest' in which the IOC bears (or "carries") all of the costs incurred prior to the state oil company's election to participate and there is no repayment of the state oil company's share of the costs incurred before the election to participate (as in Cameroon, Chad and Trinidad & Tobago). This is also known as a "hard" or sometimes as a "free" carry.

In all cases the state oil company is responsible for its proportion of petroleum operations costs following the exercise of its option to participate. These different forms of carry can perhaps be better understood by way of an example:

Pursuant to Article 2.4, the Initial Interest provides for state participation from the start of the contract and that the Initial Interest is a Carried Interest with respect to Exploration and Development Operations. This means, per the definition of "Carried Interest", that the oil company (Contractor) will pay such costs and have no right of reimbursement that is, it is a full/free/hard carry. However, GNPC will have to pay its 10% share of the costs of Production Operations as stated by the last sentence in Article 2.4 above. 

In relation to the Additional Interest:

GNPC's right to acquire the Additional interest (or in industry jargon to "back-in") arises at the date of commercial discovery and it has 90 days from that date in which to exercise such right. If GNPC does not exercise its right in the specified 90 day period it will not acquire the Additional Interest. In exercising such right it is required to contribute a "proportionate share" of all development and production costs. Accordingly, based only on Article 2.5, the Additional Interest is not a carried interest from the date of its acquisition - GNPC has under Article 2.5 to pay its share of costs in relation to such interest. However, Article 2.9 goes on to provide that GNPC may on exercising its option to acquire an Additional Interest also:

This provision allows that GNPC can be carried by the Contractor for its Additional Interest share of development costs. The language is clear that this is an advance (or a loan) by the Contractor which will be reimbursed by GNPC with interest out of production after recovery by GNPC of its share of production costs. Thus, if GNPC elects to be carried in this way under Article 2.9 this will be a partial or a soft carry. However, in relation to the Additional Interest, like the Initial Interest, none of these provisions require GNPC to pay back the Contractor for a share of the exploration costs previously incurred by the Contractor. So, in relation to exploration costs, there is a full/free/hard carry for the Additional Interest as well as the Initial Interest. GNPC is not carried by the Contractor for either its Initial Interest share or its Additional Interest share of production costs. It must bear those itself, the assumption being that it will be able to afford to meet its share of costs since it will be receiving revenue or a share of production at that point.

A point of detail in relation to state participation that is relevant particularly where the participation is not from the commencement of the petroleum contract but pursuant to the exercise of an option to participate later, is whether the state participates in all of the petroleum operations under the particular contract or, on a case by case basis, in each commercial discovery or field. Looking at the Ghanaian example above, it is clear that the Initial Interest is in respect of "all Petroleum Operations under this Agreement". By contrast GNPC has the option to elect to acquire its Additional Interest in respect of each development and production area on a case by case basis. This gives GNPC significant flexibility although it also increases the complexity of administering the agreement if there is more than one development and production area under the agreement and GNPC makes different elections in relation to these. 

The significance of state participation rights involves more than just fiscal issues, so this is discussed in more detail in later chapters.

Price volatility also makes difficult the proper administration of a petroleum sector by the state. A fiscal regime designed for a world where the price of oil had never exceeded $55 per barrel (in other words, the world as it was until 2003) may not work well when the price is $100 per barrel, as it has been for the year preceding the publication of this book.

One area where petroleum regulators are often criticised is that the fiscal tools do not extract enough revenue for the state where the price of oil is very high. Oil companies are accused of earning 'windfall profits', and states want to tax that windfall.

First, let's understand the term 'windfall' profit. It is in fact a forestry term. A lumberjack must earn his wages by the hard labour of cutting down trees and taking them to market. Occasionally, however, a big gust of wind will knock down many trees without any effort by the lumberjack. These trees, referred to as 'windfall', can then be easily sold by the lumberjack who has just made a fortunate but unearned profit.

The same can be said for oil companies. When the price of oil rises significantly, it is hard to suggest that this is an 'earned' profit. There are many reasons advanced by IOCs to retain these profits, such as the fact that they permit more reinvestment to find additional production. However, the history of volatile oil prices has led many states to require an increased share of petroleum revenues when the profits rise above certain thresholds. Consequently, many states have created profit-based taxes that we must include in the fiscal toolbox.

Extra profit-based taxes may not be necessary at all where the other fiscal tools already include features that give the government a larger share of revenue when petroleum operations become more profitable. Sliding scale systems, R factors and 'internal rate of return' (IRR) features are designed to capture additional profits.

• VAT or value added tax
• import duties
• export duties
• turnover taxes
• industrial taxes
• withholding taxes

An IOC needs to be attentive to the full variety of taxes that are applicable in a particular state before investing there. Similarly, a state needs to be alert to the fact that these taxes (and sometimes the bureaucracy involved in administering them) may tip the balance for an investor so that a petroleum project ceases to be economic.

Production sharing contracts state that title to every asset that is purchased by an IOC and incorporated into a petroleum operation is automatically transferred to the state. Applying a tax to an IOC who imports the asset that will immediately become owned by the state makes little sense.

• Service Fees - the compensation paid by a state to an IOC for the performance of services under a risk service contract.
  

Risk service contracts are not in wide use around the world; only seven states use them. Consequently there is only a limited variety of service fee systems. Fundamentally, there are three types:

13. Fiscal Strategies and Solutions

The previous chapter listed the fiscal tools that governments use with IOCs to share between them the income from a petroleum project. This chapter will describe how these tools are used to create a 'fiscal regime' under a particular petroleum contract.

It is important to remember that there are over 500 different fiscal regimes in use today-- more than the number of countries in the world! Some countries use more than one type of fiscal regime. This results from the different petroleum opportunities that exist in some countries, and the different risks, costs and rewards that may be gained from these opportunities. For example, offshore oil & gas exploration tends to be more expensive than onshore, so the fiscal regime needs to be adjusted to reflect this. Natural gas projects have a different price, cost, regulatory and operational environment, so fiscal terms for gas typically are more generous to the IOC than for oil.

We're going to give away the conclusion right now: there is no single system that is the right one for every situation. There are wide differences in geological prospects, reservoir conditions, costs, prices, infrastructure and availability of services. Attractive investment opportunities can exist in each jurisdiction, and a fiscal system that works in one jurisdiction may not work in another.

• how should the fiscal regime treat changes in the profitability of petroleum operations
• what is the timing of the state's share of the divisible income?
• how much risk of success of petroleum operations is the state prepared to take?
• to what extent does the state want to encourage initial petroleum investment and re-investment?

We will examine each of these issues individually.

It is important to stress that these are not value-judgements on the fiscal regime.  To say a state has a regressive fiscal regime is not to say that is it old, antiquated and out of touch with modern reality.  There may be good reasons for a country to choose regressive fiscal tools that result in a regressive system.

A fixed royalty is another case in point.  

Corporate income tax is a neutral fiscal tool, because the tax is applied to a corporation's net income (or profit). The tax rate is the same, regardless of whether that profit is large or small. Fixed percentage profit sharing works the same way-- it is also a neutral fiscal tool.

An example of a fiscal tool that increases the state's share of profits when profitability increases is an R factor royalty or profit share.  In the Azerbaijan example in the previous chapter, the government's share of profit oil increases from 15% to 35% as R goes from zero to two. When oil & gas operations become more profitable, the R factor increases more quickly, and the state's share of profits increases.  This is an example of a progressive fiscal tool.

A fiscal tool can be regressive, neutral or progressive with respect to the three key factors of petroleum profitability, which are price, costs and production rate. A sliding scale royalty that increases as the production rate goes up is a progressive feature in terms of production, but not for price or cost. A sliding scale based on the price of oil would be price-progressive but not cost or production progressive.  Sliding scales using R factors or internal rate of return focus on overall profitability, and therefore they tend to be progressive across all three features. 

Moreover, the fluctuating profitability of the oil & gas industry is bound to lead to situations where an IOC's operations become very profitable at some times during the long term of a petroleum contract.  States tend to be irritated when IOCs profits go up while the state's share of those profits go down or stay the same.  This fact is one of the reasons why states often change the fiscal regime during the term of an investor's operations, leading to instability and friction between state and IOCs.

Creating progressive fiscal features that give a state an increasing share of profitability is one way that this area of potential friction can be addressed.  If a suitably progressive fiscal system exists, then a state should be pleased when oil industry profitability goes up, because the state's share of those profits will also go up.

Two notes of caution are in order when dealing with this approach to profitability.  First, oil industry profits don't always go up; prices and costs go up and down.  There are times when an IOCs activities may be unprofitable.  If a state's share of revenues drop to zero in such circumstances, that can also be irritating to a state, and the state may not be readily able to deal with such an absence of revenue.  So, there is a strong case to be made for regressive fiscal tools that generate government revenue whenever oil & gas is produced, and regardless of whether the activity is profitable.

Second, a fiscal regime that takes away too much of an increase in profitability can result in a situation where this acts as an incentive to increase costs.  Economists refer to this behaviour as 'gold plating', because the IOC has an incentive to incur excessive costs (such as an imaginary plating of the facilities in gold) or no incentive to reduce costs.  A regime can be tested for its goldplating by the use of a financial model; if an increase in costs by a dollar results in government revenues reducing by more than a dollar, then it's a goldplate. Such regimes may also create incentives to the IOC to reduce the production rate or sell production at a discounted price, which have similar effects as goldplating.  

Goldplating results in a misalignment of the interests of the state and the IOC.  Fiscal systems work better when the IOC has a financial incentive to achieve the same result as the state, which generally is to increase production at the highest price and the lowest costs. 

Most states choose a variety of fiscal tools resulting in a hybrid system. When creating, reviewing or evaluating a fiscal regime, it is important to recognize the potential impacts of each tool in an environment where profitability frequently changes.  

• signature bonus: very regressive
• production bonus: very regressive
• fixed royalty: regressive
• sliding scale royalty: progressive
• corporate income tax: neutral
• fixed profit share: neutral
• sliding scale profit share: progressive
• state participation: neutral
• profit-based taxes: progressive
• other general taxes: varies, but generally regressive
• service fee systems: very progressive

So each of these fiscal tools can be said to be: 

• 'front-end loaded', which means that they begin to apply before the IOC has recovered its costs (in other words, the state receives revenue before the IOC is making a profit)
• 'neutral', which means that they apply only upon the IOC recovering its costs (so the state profits only when the IOC profits)
• 'back-end loaded', which means that the state's share only becomes significant after the IOC is in a profitable environment

The state typically chooses the fiscal tool based on when it wants to receive the petroleum revenue.  Naturally, states want money sooner rather than later, but IOCs would rather pay money later in the life of the project once profitability has been established.  Consequently, this is a balancing exercise.  The more that is required to be paid up front, the less can be expected as the back end, and vice versa.

There are certain parameters that help to understand the choice of the fiscal tool, but these are not included in the petroleum contract.  One such parameter is the  'discount rate' of the government and the IOC.

IOCs have discount rates too, generally in the 10-15% rate or higher, because they can put today's dollar to use to generate a profit in a year's time. So, in the balancing exercise involved in choosing the timing of the revenue, logical behaviour would be for wealthy governments to back-end load their fiscal regimes, and poor governments to prefer to front-end load. Sometimes this logic prevails, but often it does not; for example, the wealthy province of Alberta, Canada has a system that prefers up-front payments, while Papua New Guinea has a back-end loaded system.

Here is how the fiscal tools fit into the timing scenario:

• signature bonus: front-end load
• production bonus: varies
• fixed royalty: front-end load
• sliding scale royalty: varies
• corporate income tax: neutral
• fixed profit share: front-end load to neutral (depending on cost oil limit)
• sliding scale profit share: neutral to back-end load
• state participation: neutral
• profit-based taxes: back-end load
• other general taxes: varies

Service fee systems are not as easily categorized because the government pays the contractor a service fee retains all the revenues. The impact on the state and the investor varies with the service fee system that is chosen.

A state could choose to take no risk of petroleum operations by selling to an IOC the land on which petroleum operations are to occur for a defined price, without any royalty or other future payment obligation. The state's share would be unaffected by exploration success or failure, oil price fluctuations, production rate fluctuations and changes to the cost environment.However, no state takes this approach to petroleum activities. Every government designs a fiscal system that will capture some of the economic rent of a successful petroleum project. But the design of the fiscal system can affect how much of the risk of success or failure that the government is prepared to share with the IOC. For example, if a government receives a fixed royalty of 12.5%, the state does not share in the cost risk of petroleum operations: it will receive one-eighth of production, whether the IOCs operations are profitable or not. An IRR-based profit oil share will result in the government sharing all of the risks of the IOC's success, because it will receive a significant share of production only after the IOC has profited. Some states make it a strategic national goal to have a direct involvement in petroleum operations through the participation of a state oil company. This involves sharing most or all of the risks of petroleum operations. The extent to which a state bears the risk of success can have an impact on other features of the petroleum contract. If the state shares in the cost risk (for example, through a state oil company participation or a profit share), then the state may want a greater operational or approval role in the costs that the IOC plans to incur, such as a joint management committee.Here is how the various fiscal tools stack up for state risk sharing for exploration, production rate, price risk and cost risk:

• signature bonus: no risk
• production bonus: exploration risk only
• fixed royalty: exploration risk only
• sliding scale royalty: exploration risk, and some or all of production risk, price risk and cost risk (depending on the sliding scale factor)
• corporate income tax: full risk
• fixed profit share: full risk
• sliding scale profit share: exploration risk, and some or all of production risk, price risk and cost risk (depending on the sliding scale factor)
• state participation: no exploration risk; all other risk
• profit-based taxes: full risk
• other general taxes: varies
• service fee systems: full risk

Some fiscal regimes are better structured than others to make initial investment attractive.  A big signature bonus is a disincentive to invest, because it requires the IOC to pay up front for the right to explore, before it knows if the block has commercial reserves. The funds that the IOC has available to conduct exploration are reduced; maybe the amount spent on the signature bonus could have been spent on an extra well that might have been a success. Conversely, a production sharing contract with a high cost oil limit means that the IOC can recover its exploration costs (including unsuccessful wells that precede a discovery well) before the state share of revenues becomes significant.

Some petroleum contracts will result in IOCs investing in a state for the first time, and they analyse their interest in doing so by assessing the attractiveness of the fiscal regime on a 'stand alone' basis. However, most petroleum investment that happens in the world is in activities by an IOC in a state where they already have petroleum operations, often in a different block.  In such cases, the IOC will assess the fiscal regime on the basis of its overall impact on its existing and new investment. This is important because sometimes IOCs are able to deduct the costs of a new investment against the revenues and taxes paid on an existing field. This makes re-investment more attractive. An example might be useful here.

This kind of re-investment incentive happens when the fiscal regime is 'consolidated' rather than 'ring fenced'. Ring fencing was discussed in the previous chapter. Ring fencing tends to reduce the incentive to re-invest, while consolidation tends to increase it.

The various fiscal tools have the following impact on investment and re-investment: 

• signature bonus: disincentive to invest and re-invest (unless deductible against fiscal term)
• production bonus: neutral
• fixed royalty: disincentive to invest and re-invest
• sliding scale royalty: neutral on incentive to invest; reinvestment impact depends on ring fence treatment
• corporate income tax: neutral on incentive to invest; strong reinvestment incentive depending on ring fence treatment
• fixed profit share: neutral on incentive to invest; strong reinvestment incentive depending on ring fence treatment
• sliding scale profit share: neutral on incentive to invest; reinvestment impact depends on ring fence treatment
• state participation: disincentive to invest; reinvestment impact depends on whether state oil company is carried on the subsequent investment
• profit-based taxes: neutral on incentive to invest; reinvestment impact depends on ring fence treatment

State participation has the following results on the four strategic considerations:

• Changing Profitability: neutral
• Timing: neutral
• Risk: no exploration risk (where carried); all other risks
• Initial Investment and Re-investment: disincentive to invest; reinvestment impact depends on whether state oil company is carried on the subsequent investment

The state's share of profits will be the same as the IOC's share because the state oil company's participating interest share typically is a co-investment by the state oil company and the IOC. For the same reason, the timing of the state's share of revenues is neutral as well.

Except for a 'full equity' state participation, the state does not bear exploration risk, because the typical state participation right is an option for the state to participate at the time of a commercial discovery. If exploration is unsuccessful, then the state does not participate, and the IOC bears all the cost of failure. If exploration is successful, then the state will elect to participate.

This is a very attractive feature for the state-- it's a risk-free bet on exploration success. Some states like this so much that they seek to increase this as a feature of the fiscal regime. The problem is that, depending on the percentage of carried participation, it can have a seriously negative impact on the attractiveness of the initial investment by the IOC. Let's use a simple example to explain this.

State participation rights work in a similar way. The economic impact to the IOC of a carried participation affects what the economists call the 'maximum sustainable risk'. If you take away too much of the exploration incentive, it's simply not worth playing the game. This is why a carried interest for the state is a disincentive to invest, and the larger the carried interest, the greater the disincentive. It is also a disincentive to re-invest if the state oil company is also carried on the re-investment activities. Nevertheless, this is a fiscal feature that more states are adopting.

• low or no signature bonus
• low rental during exploration phase
• full deductibility of exploration expenditures under corporate income tax
• high cost oil limit in production sharing contract
• avoid carried interests for state participation

• avoid IRR-based sliding scales
• avoid R-factor systems with high marginal tax rates on profit oil
• avoid uplifts where the IOC is entitled to a deduction of greater than 100% of any cost

Also, service contracts tend not to promote cost-effective operations, because the IOC has no financial incentive to minimize cost under most service fee structures.  

• use sliding scale royalties based on production rates
• allow high depreciation rates for development costs
• allow full consolidation for corporate income tax
• avoid high fixed royalties
• allow high cost oil limits (or none at all)
• utilize IRR and R-factor systems

• lower royalty for gas
• high depreciation rates for corporate income tax on gas pipelines and other facilities
• high cost gas limits, lower profit gas share for the state
• exempt gas projects from special taxes
• exempt gas projects from carried state participation

Service contracts are particularly challenging in this regard. States want more oil production at lower cost and higher prices. Yet service contracts tend to create structures with minimal incentive to the IOC to increase the production rate, and no incentive to keep costs low.

The same situation arises in other types of petroleum contracts where the fiscal regime is excessively progressive. This leads to distortions in IOC behaviour; there are examples where under certain conditions a petroleum project may be more profitable with higher costs than with lower costs, or the incentive to reduce costs is so minimal that the IOC tends not to do so.

Production sharing contracts tend to involve a higher degree of administration, because the state needs to be concerned about costs. Authorizing expenditures, accounting for costs and auditing IOC activities are now required.  

State participation adds another layer of administration. The state oil company as a co-contractor now is also involved in approving activities and expenditures, accounting and auditing. 

For states that have the technical, administrative and financial capacity to administer complex systems, these structures may make sense.  For those states who do not, a better approach may be to keep administration simple.

'Conventional' oil & gas is found in subsurface reservoirs of porous rock where petroleum is 'trapped' by the surrounding geology.  As the world's conventional oil & gas resources are becoming more scarce, IOCs are focusing more on developing and producing oil & gas from 'non-conventional' (sometimes called 'unconventional') sources.  

This means oil & gas produced or extracted using techniques other than the conventional  methods. Non-conventional oil & gas production is a less efficient, more expensive process and often has greater environmental impacts than conventional oil & gas production.

One way to look at this shift to non-conventional is to compare conventional petroleum resources to the best parts of a cow.  (Apologies to vegans and Indians).  

Conventional oil & gas is like the tenderloin and sirloin-- it's the 'steak' of the petroleum cow.  It is comparatively easier and less expensive to find and develop, and it's the tastiest part too.  However, just as we eat other parts of the cow, there are other parts of the petroleum cow that can produce oil & gas too.  Shale gas, coalbed methane, oil sands, ultraheavy oil can also be produced.

However, just as the brisket and shank of a cow cannot be cooked like a steak, we need different 'recipes' to make the rest of the petroleum cow attractive.  Different fiscal terms are required in order to make attractive these more costly, and often less valuable resources.  Also, different tenure regimes are often required.

This is the trend in advanced petroleum states today.  The province of Alberta, Canada has five different fiscal regimes to make investment attractive for its conventional oil & gas, oil sands, heavy oil, coalbed methane and shale resources.  Other states are following this trend.

14. Comparing Results

As previous chapters have described, there is a wide range of fiscal tools and almost limitless ways of combining them, so that, in combination with other factors which are unique to each oil project such as costs of production and geological prospectivity, each contract seems to encompass what amounts to its own fiscal ecosystem.

The challenge in assessing and comparing them is that petroleum contracts each have different fiscal terms that combine:

• amounts paid before oil is discovered (signature bonus, rental)
• fixed payments made when oil is discovered and produced (production bonus)
• payments based on the quantity of production (fixed royalty)
• payments that adjust based on the quantity, type or price of production (sliding scale royalty)
• payments based on the profitability of the field (fixed profit oil and cost oil)
• payments that adjust based on the profitability of the field (sliding scale profit oil and other profit-based tools)
• payments that are based on the profitability of the IOC conducting the activity (corporate income tax)
• provisions that puts the state into the position comparable to that of an IOC (state participation)

As an example of the challenges involved, try to select which of the following options is best for the state, or best for the IOC:

Option A: 

1. 5% Royalty
2. 30% Corporate Income Tax
3. Production Sharing of 40% in favor of the Government
4. State Participation of 15%
5. Withholding tax on services at 5%
6. Withholding tax on dividends at 5%
7. Withholding tax on interest at 5%
8. Signing Bonus $20 million 

Option B:

1. 35% Corporate Income Tax 
2. Production Sharing 60% in favor of the Government
3. Signing Bonus $30 million

Option C: 

1. 51% State Participation
2. 25% Corporate Income Tax Rate 
3. Signing bonus $60 million

You may have already guessed that there is no right answer. Even though there are 8 ways in which the state can receive money under option A, it is not necessarily the best option. And what about those higher production shares and state participation in B and C?  How do we know which one is more attractice, especially when combined with the other fiscal toold?  It all depends on whether there is a discovery, and if so, the costs, prices and production rates of the project.

Yet there is an inevitable desire to find a way to compare different fiscal systems. As information flows increase around the global oil and gas industry, people naturally seek to know if they and their government are doing OK, and to boil that down into one single figure.  How do you know if your competitive?

The way this has traditionally been done is through a metric called 'government take', as described above.  Government take is the percentage of the divisible income (lifetime project revenues minus lifetime project costs) the state will receive over the lifetime of the project.

The principal reason that one country can have a very different government take than another is that it is a competitive system at an international level: a state that has good geology can demand tougher terms from IOCs. 

But before we think everything has become easy and all we need is government take, there are several limitations on the usefulness of it as a measure. One is that it is based on an assumed oil price. As we have seen, very few contracts remain neutral when the price of oil changes. Most are either progressive, meaning the government earns a higher percentage when profits go up, or regressive, meaning the reverse. Consequently, rankings may change under different price scenarios.

Second, the rate of return is against the expected total production out of a project - and yet that figure also changes over time. It is quite usual for projects to begin on the basis of a known amount of proven reserves in a contract area but for those reserve figures to go up during the lifetime of the project. This is because exploration is more successful once the local geology is understood, as well as the fact that there is more incentive to explore near existing wells because a route to market has already been built. So a project might start on the basis it was going to produce 50 million barrels and end up producing 70 million barrels. Or, conversely, there may be issues of reservoir management, or disruptions which cause production to decline faster than expected.

Third and most importantly, the government take is the estimate of what percentage of profit will be over the lifetime of the project. But that could be 20 years or more and few governments are indifferent to when they get the money. As we have seen in the previous chapter, the timing of receipt of the state's share of revenues varies from country to country.

This has led to the evolution of a different measure, the Effective Royalty Rate (ERR), which tries to work out the profit a government receives during any given accounting period. The ERR is often much lower than a government take statistic in the early years of a project because of cost recovery, the fact that the oil company is recovering large amounts of costs sunk into developing the oil fields in the first place.

But it is important to realise that companies are mostly guided by different measures than 'contractor take'. One such measure is the Internal Rate of Return (IRR). The IRR is used to measure and compare the profitability of investments. The higher a project's IRR, the more desirable it is to undertake the project. Contractor take and IRR are very different calculations.  

It is becoming more common for states to include progressive features in the fiscal regime of petroleum contracts to capture more of this rent. So in principle, government take and IRR could both rise in some circumstances. The zero sum game is not inevitable.

So far so good. But there is another very important way in which governments and companies are often in intense zero sum competition over fiscal terms. Because both of them are often interested in how much money they can get now - or as close to now as possible. This is the timing issue: will the state receive its share of government take early or late in the life of the project.  For a country where oil is being produced by an IOC there is pressure to show results soon. In many cases, though, the need is also urgent and practical. Public services and civil service payrolls routinely depend on having money to spend, a syndrome which is heightened during elections and other political events. And yet the first years of the project are when a company will be anxious to recover its investment to that its IRR improves.

So sometimes countries may need to ignore the reductiveness of comparing themselves through a single figure like government take, and define a peer group for themselves of other countries which they regard as similar for a variety of reasons - e.g. they are neighbours, or have similar kinds of 'prospectivity' - amounts of oil in the ground - and are at similar stages of production.

15. How big is the pie?

In order to decide who gets what, you have to know how big the pie is. That's why every contract spends time laying out what oil and gas is worth in some detail. Knowing how much oil is produced and sold is crucial in determining the size of the pie as well. Getting a good idea of how big the pie is can be quite complicated for the following reasons:

• A barrel of oil is not a barrel of oil is not a barrel of oil. Some crude oil is worth considerably more than other oil for either chemical or marketing reasons.
• A lot can happen on the way from the well head to the refinery or shipping terminal. Think of Nigeria where illegal tapping into the pipeline to divert crude on its way to the sea has become virtually institutionalised as its own economic sector.
• Sometimes companies have much more experience and access to the international markets which define the price of oil than governments. The could leave governments at a disadvantage in calculating how much they should be getting. This sometimes leads to the definition of two ways of pricing the oil, which can be categorized as arm's length pricing and formula pricing.
• Governments often want part of the crude oil for their own use. Companies want to sell as much of the output as possible for the highest price possible. This potential conflict of interest is dealt with in clauses mentioning what is sometimes known as domestic market obligation.
• Natural gas, often found with oil, throws complicates things, since these contracts have been designed with oil in mind.

Let's look at each of those in turn.

The most valuable crude is 'light' and 'sweet'. Countries like Libya are lucky enough to have this type of crude. Legend has it that you could take the oil straight out of the ground and put it in the tank of your car and it would go, at least for a while. At the other end are grades of crude oil which are 'heavy' and 'sour', such as those produced by Iran and Venezuela.

The difference between high and low quality crude oils is in the amount of processing and refining needed to transform the raw material into usable products. The less refining needed, the cheaper it is to make the raw crude oil into a valuable product, which is why we consider it to be of a higher quality. The scale of 'sweet' to 'sour' refers to the amount of sulphur contained in the oil. Sweet crudes have a low sulphur content, sour crudes have a high sulphur content. As the sulphur has to be removed before anything useful can be made, sweet oil is much more valuable than sour oil. The range of 'light' and 'heavy' refers to the density of oil, which is measured using a scale developed by the American Petroleum Institute, called API gravity. The higher the API number, the lower the density, and the 'lighter' we say the crude is. 'Light' crudes can be refined, or distilled, into higher value products than 'heavy' crudes, so it is of higher quality. In the jargon, it has a better distillate yield. Half of a barrel of heavy oil might end up as tar, only useful for paving roads, with only a small quantity of petrol or gasoline that can be sold to car owners. There is more demand for products which can be made from light grades of crude oil, such as diesel and gasoline. See Ghana's example of this below.

The Ghanaian clause above illustrates that the quality of crude oil could differ significantly even within one license area. One well may contain good quality crude, another well might contain less good quality crude. Ideally you need to keep track of how much of each type of oil went down the pipeline. But how? The contract will usually say that you either build infrastructure to keep them separate and agree a way to calculate the price for each, or you mix them and agree on a merged price.

The distance from a wellhead to a storage terminal is often hundreds, sometimes even thousands of kilometers. What if the company says they produced a million barrels of oil in July from that field, but the government says, wait a minute, only 950,000 barrels turned up at the port! At current market prices, five million dollars have gone missing.

The above-mentioned Ghana contract then goes on to state that although the government can order inspection at any time, at the company's expense, the company can claim back the expense if the tests show the oil in storage at the end of the line is the same as was stated in the company's records "within acceptable tolerances". It is not clear in the contract itself what level of 'tolerance' is acceptable. Companies that sell oil meters, which can cost hundreds of thousands of dollars, now guarantee accuracy to within 0.15% of total volume. The reason there would be any discrepancy at all relates to the previous section and different grades of crude oil. The terms 'light' and 'heavy' are literal, not figurative. So if you 'blend' several grades of crude oil with different physical weights it will be hard to achieve absolute accuracy even with modern technology.

The vulnerability of oil as a valuable commodity coming out of often poor and remote areas leads to emphasis being attached to another clause in contracts related to valuing petroleum: specifying the handover point, or point of valuation. Sometimes this is at the field itself, sometimes at the other end of the pipeline and sometimes into a storage tank, depending who controls it.

The agreements which govern most of Libyan production, for example, say that the IOCs have to accept a valuation of their share of oil based on what the Libyan state itself has been able to sell it for on international markets. Luckily for oil companies, the Libyan state can usuallly sell the crude for the same price the IOCs would sell it for.

Indonesia's contracts envisage a more intermediate situation. Indonesia is an established oil producer and its state owned company Pertamina has a sales and marketing division. On the other hand, the agreement from 1998 with Unocal Ganal, says the share of the oil of Pertamina will be valued at whatever the contractor could sell it for on world markets. But if Pertamina is able to find a better price on the market itself, then Unocal has to either meet the price or allow Pertamina to market the oil itself. It looks like the contractor will do most of the selling, but Pertamina will keep them on their toes.

In new petroleum producing countries, the company will typically do most of the selling. Therefore governments sometimes find it useful to include a clause in the contract that specifies the way of calculating the price of their crude oil. This is known as a formula pricing.

Ouch! Don't worry, it's not necessary to understand all of that. Here's what the letters mean:

• P = Price of the crude produced from this field
• B = Price of Brent, a crude oil that comes from the North Sea
• U = Price of Urals, a crude oil from Russia
• A_P-B = references to the grade of Afghan crude, as measured on the API Index
• the S, T and D are not really important for the purpose of this example

So the formula basically says that the parties agree to price this crude oil partly by its API grade and partly against whatever Brent and Urals oil sells for on world markets. The higher the quality of the Afghan crude compared to the quality of Brent and Urals, the higher it is priced.

Brent and Urals in this case act as 'benchmark crudes'. There are thousands of grades of crude oil around the world and in many cases they get benchmarked against Brent, Urals, or the likes. You may never see the actual price of each of the existing crudes. Their price is referred to as simply "Brent minus $7.15", for example, or "Urals plus $3.42".

This Afghan agreement assumes that the contractor will sell the oil. But it provides an assurance to the government that there is a baseline value to the oil that the government can work if needed. There are dozens of accounting firms or petroleum economists who do understand the formula above, and will be able to tell the government the amount of money the crude should have been sold for at each point in time.

Using an "arm's length" standard is another way the parties to the contract sometimes deal with calculating the price against which the crude should be sold.  Transfer pricing may happen when, for example, a subsidiary company buys or sells crude that is priced artificially high or low to or from its parent company. Companies will want to do that for accounting purposes, so that they can make sure that the highest profit is booked in the jurisdiction with the lowest tax on profits. By including a clause requiring arm's length pricing of the crude the government makes sure that transfer pricing cannot occur. By refering to an arm's length standard in the contract, the parties are acknowledging that related party transactions occur and that is fine, so long as the country still gets a fair price for the oil sold. 

Oil might be valued at the price it is actually bought if it is being sold to non-affiiliates of the selling company, also referred to as independent third parties.  In this case, the parties might use this price since it should represent an arm's-length fair market price for the crude.

Generally speaking, companies can be nervous of domestic market obligations. This is because the obligation is a restriction on how much oil and gas can be sold on world markets against international prices. Domestic market obligations can sometimes result in the selling of crude to the state against at a price below international prices, thereby negatively affecting company revenues. States on the other hand often regard domestic market obligation clauses as very valuable because they want to ensure that its own economy has enough crude when it needs it. In order to reassure the contractor that prices won't drop too much compared to international market prices, a provision ensuring arm's length pricing is included.

16. History and Evolution

As discussed earlier, oil and gas together constitute the largest source of energy for the modern world. However, in their natural state, they are only found in certain parts of the world. In the early years the demand in developed countries far exceeded local supplies, while in developing countries the supply far exceeded the demand. In addition, oil producing developing countries did not have the infrastructure for refining the crude, nor the markets for absorbing the refined products.

As a result, the structure of the industry was largely shaped by supply and demand conditions: oil producing developing countries mainly exported crude to the larger developed countries' markets, where processing took place and the final products were sold. The contractual terms mainly focused on fiscal terms and financial gains, which reflected this preference for obtaining revenues from royalties and taxes rather than production sharing.

Generally speaking, the contractual provisions reflect these objectives, for example by focusing on increasing the participation of the local workforce, and using local goods and service companies in the petroleum sector in order to increase employment and to build experience and competitiveness in the long run. These provisions are often referred to as "local content" and will be elaborated later.

This can by seen through a plethora of recent regional and global initiatives calling for a greater role of the petroleum industry to stimulate national economic development. For instance, at a global level the Natural Resource Charter with its twelve precepts provides a set of principles for governments and societies on how to best harness the opportunities created by extractive resources to contribute to the country's overall development. These precepts are underlined by illustrative case studies such as Norway's path to inclusive and sustainable development through a comprehensive resource development strategy and institutions promoting democracy and education for long term development and competitiveness.

An example of such an initiative at the regional level in the mining sector is the Africa Mining Vision. This provides a continent-wide strategy aimed at advancing the contribution of mining to economic development. They do this by creating refining capacity where economically viable, strategically linking infrastructure created in the oil and gas sector to other sectors of the economy, building the capacity of the local workforce and local companies to participate in the petroleum sector, and by spending the revenues on strategic sectors that spur long-term growth and competitiveness. This requires a lot of government capacity in terms of strategic planning, active involvement in implementation of the plans, and the monitoring progress.

Another tendency may reflected in the contracts, or at least in the negotiation rounds, is the desire of producing governments no longer just want to export their petroleum but to retain an increasing part of it to help satisfy their national energy demand, and to add economic value by refining the crude in the host-country if economically viable. Most contracts have a provision stating that the Government can require the oil companies to supply a proportion of their petroleum to the State in certain circumstances, or require national energy demand to be fulfilled first before exporting crude is permitted. Many new petroleum producing countries are discussing whether or not it is economically viable to refine the crude before exporting it.

Countries are increasingly linking up or working together with their neighbours. In the future oil contracts might be used to stimulate and take advantage of regional trading blocks which will create larger markets, especially amongst countries with smaller economies and labour forces. This would expand the potential market for local content from one country to several more, which could stimulate individual countries to specialize in those goods and services they produce or develop most productively. It could also create regional infrastructure linkages, or it might be an argument to develop refining capacity in one country if the crude supplied by its neighbouring countries can be refined there as well. Implementation of such plans will require proper regional planning and the cooperation of governments.

Oil for infrastructure deals are a recent phenomenon to spur economic development and will be discussed in a later chapter. The same holds true for local content as well as the possible non-fiscal benefits through state owned petroleum companies. The so-called domestic market obligation is another tool that can be mentioned here. It is mentioned in a number of contracts requiring the IOC to sell some of the exploited petroleum in the host country often constituting a crucial contribution to the national to energy supply. This provision is dealt with further in the chapter "How big is the pie?".

17. Oil for Infrastructure

A new phenomenon is the exchange of oil for infrastructure. This means that the host country gives up some parts of traditional taxes such as royalties, withholding taxes, corporate taxes etc. in exchange for physical works in the form of building roads, railways, telecommunications or airports. Chinese investors, usually with backing from their government, have led this movement. Unfortunately, very little information is available on the details of the provisions of agreements covering this type of deals. Through these deals the government is able to provide its citizens with major infrastructure works in a short period of time, sometimes far before petroleum production starts. This can be an important reason for agreeing to an oil for infrastructure deal, especially when elections are on their way. In addition, if the infrastructure is strategically built, it can enhance the economic development of the country by connecting markets and reducing transportation costs. Re-payment of the debt for building the infrastructure is not made from earned income but from potential earnings. However, the way in which these potential earnings are calculated and the way in which any differences between project petroleum prices and actual ones are incorporated is not clear. From the government point of view, a comparison could be made with using a credit card while the interest rate for pay-back is unknown.

In sum, the oil for infrastructure displays the following characteristics:

• It is a visible demonstration of the transformation of assets in the ground to investments above the ground and one that can yield benefits for future generations who will be able to use the infrastructure built. However, the government must ensure that the quality of works is up to standards so that the infrastructure will last for a while;
• The speed with which the infrastructure is produced reduces the cost to the home country compared to the costs normally associated with developing a large infruastructure project. Usually funds need to be mobilized and part of the contract might go to waste due to corrupt practices. However, the terms of the agreement must include standards and deadlines as well as sanctions in case the work is of poor quality or not delivered on time.
• The host country must calculate carefully the likely projections and long term trends for the petroleum reserve against which the infrastructure work is 'mortgaged' and obtain as much detail as possible on its size, accessibility, and quality to be sure it is getting a fair deal. Differences between actual and predicted future crude prices and the effect on the value of the deal should be included as well.
• The government should make sure that feasibility studies as well as environmental and social impact assessments are conducted for the work, as they would be if the government had procured the work itself.

18. The role of the National Oil Company

The chapter on the Fiscal Toolkit in this book deals with state participation by a state oil company as one of the fiscal tools a state can use for sharing the profits of an oil and gas project. However, a state rarely establishes a state oil company merely to increase its share of the pie. A state oil company may be a vehicle to help deliver other, broader development goals. The state may see the establishment of a state oil and gas company as a means to create local employment and acquiring technical know-how on the oil and gas sector.

There are many examples of state oil companies: Saudi Aramco, Statoil, Petronas, Petrobras and CNOOC to name a few. State oil companies come in all shapes and sizes and are established with differing objectives in mind.  There is a significant amount of literature on the pros and cons of pursuing national development goals through a state oil company. The purpose of this chapter is to show that state oil companies may be a vehicle through which states can pursue other benefits than merely financial ones.

Such contracts have their own governance arrangements and are discussed in the section: The Actors and the Script. As a participant in these arrangements the NOC may have greater visibility of and an opportunity to scrutinise decisions relating to the conduct of petroleum operations. It can provide information on the petroleum operations that would not otherwise be available. To the extent that the state's interest is not "carried" but it is paying its share of costs, the state has "skin in the game" which may alter its perspective and provide incentives to find and produce oil. So some of the incentives of the government and oil companies are better aligned if the state oil company participates. Other factors, such as cutting costs on environmental protection by the oil companies, might not be in the interest of the state.

State participation in an oil and gas development via a NOC may also provide the NOC with opportunities to involve its personnel in the conduct of petroleum operations through secondments to the operator and/or through participation in training programmes that the operator has in place for its own employees. This is often specified in the contract under provisions about local content and/or training. This is aimed at provide some form of knowledge transfer and capacity building. More ambitious arrangements may involve personnel from a NOC working alongside their international oil company counterparts and "learning by doing". Ultimately, the NOC may acquire the ability to operate both within its own jurisdiction and abroad. 

The creation and development of a NOC as the vehicle for state particpation also provides employment opportunities within the NOC and the ability to drive greater "local content" in terms of directing purchase of local goods and services. See the chapter 'Procurement, Employement and Social Welfare' for further information.

The second potential disadvantage is that state participation through an NOC may complicate the relationship of the state and its contractors. In a number of countries, the NOC may be playing the role of a commercial enterprise to be regulated by the state and, at the same time, be the body that is entrusted with regulating the petroleum sector. There is a clear danger of a conflict of interest in this scenario. Even where the regulatory function is carried out by the government and the Ministry of Petroleum and not by the NOC, the mere existence of a NOC alongside the regulator can create the possibility for "turf wars".

19. Employment, Procurement and Social Welfare

Local content is a term which is increasingly used in petroleum contracts ensuring that the company is hiring local labour and procuring local goods and services from the host country instead of using imported goods and services or foreign workers.

Instead of using the term local content, a handful of contracts refer to 'national content', because the term 'local content' often brings to mind a much more localized geographical area, i.e. the project-affected area instead of the host-country in general. To cut a long story short, the terms are used inter-changeably and cover the same issues.

Often it is assumed that social welfare issues or corporate social responsibility (CSR) considerations are also included in local content. This is not the case. Social welfare is dealt with at the end of this chapter.

Several countries have developed local content policies and laws. For example, Ghana has a Local Content and Local Participation Policy (2010) specific to the petroleum sector. Kazakhstan instead takes a more general approach to local content requirements by including it in its Procurement Law. Brazil and Nigeria have also developed local content legislation.

Many countries do not, or not only, address local content issues in legislation, but address them directly in petroleum contracts. Even if local content legislation does exist, local content is often still addressed in the contract with more specificity.

However, not all contracts include local content sections, even if there is no local content law in place. Contracts generally do not discuss local content in more detail than a couple of sentences. Below, you will find a brief outline about the general character on local content provisions.

With this type of general language the challenge arises on how to monitor if company has complied with the obligation. Some contracts therefore specify a percentage of required local personnel the company will need to employ. This is sometimes broken down per job category, and sometimes the percentage increases over time. This can be problematic given that the percentages might have been chosen arbitrarily. It is often difficult to have a good sense of what percentage is realistic and achievable. Another issue is that contracts very often do not specify the base which will be used to calculate the percentage. Are talking about a percentage of part-time or full-time employees, full-time equivalents, or would a general headcount suffice?

In addition, stating specific job categories such as skilled, unskilled, technical, administrative, clerical, management, etc. can lead to differences in interpretation of what these mean and the qualifications needed. Definitions, interpretations and requirements for these job categories often differ between different parts of the world.

Some contracts do not further expand on the local labour requirements to address how compliance will be monitored. The result often is that in this case the requirement will not be monitored at all. Some contracts do have monitoring provisions, in which the company is required to submit a local content or employment plan, which then requires government approval. Sometimes the contract requires the employment plan to be included in the Annual Work Plan.

• train nationals in order to employ them directly in the future
• train existing employees to take on jobs that require higher qualifications and more skills
• train employees of the national petroleum company

Sometimes a fund is set up into which the company disburses an agreed amount of money that is used for training purposes. Many times it then remains unclear from the contract who is responsible for conducting the training and managing the fund. Sometimes the company is required to transfer funds to the national petroleum company for training purposes, implying that the national petroleum company is responsible for conducting the training. In some cases in which the company is responsible for conducting training, it is required to submit a training program for approval. Some examples are given below:

The way in which requirements for the use of local goods and services are usually framed in contracts is along the following lines: the company has to give preference to local goods and services, provided that these are similar to imported goods and services in quality and price. This is illustrated by the following examples:

These clauses can be challenging in countries new to the petroleum sector and in countries where the manufacturing and services sectors are underdeveloped and not competitive. In these cases, goods and services might not be available at all, or if they are available they might costs a whole lot more or it will take more time to deliver them, which can have implications for the costs and delivery time of the project. Some contracts allow the local goods and services to be a bit more expensive than the imported goods by a certain percentage (which is usually 10 - 15%). Other contracts refer to applying arm's length transactions in order to compare true and actual market values. Two examples are given below:

But most contracts do not include these price specifications, nor do they specify what efforts the company should make to find suitable local goods and service providers. The government or the national petroleum company could play an important role here. For instance, some governments provide the company with a list of qualified local goods and service providers and the IOC is only allowed to contract companies included on the list.

On this note, in Brazil, the contract does include the obligation of the contractor to "keep itself updated about Brazilian Suppliers capable of meeting supply needs, through trade associations, trade unions or other informed sources" while at the same time, the petroleum sector regulator registers 'certifiers', i.e. companies that provide certificates to local goods and service providers in order for them to be able to participate in the supply chain for the industry. Petroleum companies are only allowed to procure from certified suppliers. Further, some contracts specify a target in the form of a percentage for procuring local goods and services. For example, in Libya the operator is required to spend 50% of the approved budget on local goods and services.

Another issue arises with the definition of 'local' or 'national' goods and service providers. When is a company considered to be a national company? Is it when its shareholders are from the host-country? Is it when it has an office, or its headquarters in the host-country? Is it when the members of its board of directors were born in the host-country, or should the majority of the workforce be from the host-country? Is it when the goods and services are actually produced in the host-country? Contracts usually do not define what 'local' or 'national' means, which might create differences in interpretation of the term to the parties to the contract.

In Kazakhstan the term 'national' is clearly specified. A company with more than 50% foreign shareholding is considered as foreign and therefore excluded from participation in public procurement tenders, unless it fulfils all of the following criteria making it a 'national producer':

• the company is resident of Kazakhstan
• the company produces finished products in Kazakhstan
• no less than 85% of its employees are of Kazakhstan nationality

In Libya the contract specifies that the contractor is obliged to procure goods and services 'available' locally, which loosens the definition substantively as it does not require the goods to be produced in Libya, nor does it require Libyan ownership of the company that produces the goods and services. In Brazil, only the 'value added' to the good or service in Brazil counts as a contribution to national content. 

Some contracts require local content or local procurement plans to be developed by the company, approved by the government, and in some cases included in the company's annual work plan. This way the government can better monitor and oversee what efforts the company is making to comply with the local contract provisions. An example is Afghanistan:

Very few contracts specify the consequences for not adhering to local content clauses. This means that a breach of local content requirements will be dealt with in similar ways as other breaches of the contract. An example of a contract that does include a clause on the consequences of breaching local content requirements is given below.

This Brazil clause has not always been effective in serving its purpose. For example, an international petroleum company deliberately including higher local content rates in its bidding documents than it could realistically achieve, resulted in the company winning the bid but failing to achieve its local content requirement. The company was prepared to pay the resulting fine, which compared to its profits from the field was a relatively small amount to pay.

Including provisions requiring the procurement of local goods and service companies does not mean that this automatically leads to a contribution to economic development or the competitiveness of the country. In Nigeria the local content requirements of partnering with a Nigerian company have lead to corruption and the creation of shell companies. Effective local content implementation requires lots of planning, implementation and monitoring efforts of the government.

Most companies address social welfare issues in their voluntary corporate social responsibility (CSR) programs. Social welfare issues are increasingly covered under national and international law. There are also numerous good practice and standards in the area of corporate social responsibility, such as the International Organization for Standardization's (ISO) guidelines 26000 on social responsibility and the Social Responsibility Working Group of the Global Oil and Gas Industry Association for Environmental and Social Issues (IPIECA). These provide good practice on human rights, social impact assessments and community outreach. The IFC Performance Standards include standards on engaging with indigenous peoples, social impacts, and cultural heritage, for example.

Sometimes social welfare is taken up in the contract. For instance, the Production Sharing Agreement of Liberia at Clause 29.3 includes language on social welfare programmes although it does not define what 'social welfare' means exactly. The contract requires the company to provide specific amounts of funding for social welfare programs. The expenses are recoverable costs and the social welfare programs to be implemented need to be mutually agreed upon by the state and the contractor. In Pakistan petroleum contracts, the company is required to allocate minimum amounts of expenditure on social welfare programs during the exploration and production phases. The funds need to be spent to 'give lasting benefit to the communities', and any programs need to be agreed with the local community.

20. It's important isn't it?

How do petroleum contracts address concerns relating to the potential environmental and social impacts arising from the conduct of petroleum operations and the need to conduct such operations in a safe manner with regard to employees, the environment and local communities?

Perhaps surprisingly given the importance of these issues, petroleum contracts often do not deal with them in any great detail. This reflects the subsidiary importance historically attached to these issues when compared with the core concerns of finding and monetising petroleum. As a recognition of the importance of social and environmental issues in an overall sustainable development context has grown, so is an observable trend for petroleum contracts to address them with greater specificity.

Social and environmental issues, to the extent addressed, are often lumped together under the rubric of "Environment, Health and Safety" or just "Environment". This means that the health and safety and social impact provisions, if they exist, may be difficult to locate in the contract. In part, this reflects the reality that, rightly or not, environmental concerns get significantly greater attention in petroleum contracts than concerns relating to health and safety and social impacts.

The field of social impacts is an emerging area. Such impacts include, for example, increases in the price of local goods and services, immigration into the project area causing pressure on local public services and the spread of infectious diseases, resettlement and compensation, potential human rights implications, impacts on livelihood-generating sectors such as fisheries and agriculture and particular impacts on indigenous peoples and vulnerable groups. So far there are currently few examples of petroleum contracts dealing explicitly with social impacts.

Whilst the petroleum contract may not contain extensive provisions in relation to these issues all hope is not lost. One has to look also at laws and regulations that contain rules relating to the environment and health and safety to get a full picture of the obligations on an oil company in these areas. Sometimes the applicable environmental law requires attention to be paid to potential social impacts of the project. International standards and good practice usually do include social issues.

There are several provisions in petroleum contracts that indirectly address social, environmental and health & safety issues. For example, at a minimum the contract will require petroleum operations to be conducted in accordance with applicable laws and accepted industry standards or practices. There is usually a specific provision designed to pre-empt any harm that may be caused by petroleum operations by assessing what impacts such operations may have and establishing a baseline against which actual impacts can be measured (such as requirements for environmental (and social) impact assessments, baseline studies and requirements to obtain necessary environmental approvals and permits). There should then be a provision designed to ensure that, where harm arises, oil companies take responsibility for such harm and are able to meet the costs of mitigating such harm, including requirements for insurance and allocation of liability. In most contracts there is also a provision designed to ensure that, at the end of petroleum operations, the environment is, so far as possible, returned to the state it was in before petroleum operations started, which is referred to as "decommissioning" or abandonment".

How petroleum contracts address these four areas is dealt with in more detail in the following four chapters of this section. In relation to the requirement to comply with applicable laws, whether or not this expressly refers to laws relating to the environment, it will require that the oil company conducts petroleum operations in accordance with environmental laws and regulations to the extent that they are relevant to such operations. The question as to whether this will ensure adequate protection for the environment will then depend solely on whether the country in which the oil company is operating has in place suitable environmental laws and regulations and the capacity to monitor and enforce compliance with them.

Whilst the obligation to comply with laws is relatively straightforward, the requirement to comply with "industry standards" is more challenging, since what constitutes industry standards is a question that does not have a simple or single answer. Sometimes the contract may try to define the obligation to comply with industry standards at length. Two examples of this are the Iraqi model form Technical Service Contract and the 2012 Model PSC of the Government of the Kurdistan Region of Iraq. The Iraqi model form TSC requires the oil company to:

The Kurdistan PSC provides at Clause 37.1 that the oil company must comply with "Best Practices" that are defined as:

These lengthy definitions contrast with, for example, the Angolan model form PSC and the 2000 Ghanaian model Petroleum Agreement which have shorter form formulations. The Angolan model form PSC has no article that is specific to environmental issues but includes in Article 14 (which sets out generally the obligations relating to the conduct of Petroleum Operations) a general requirement to act "in accordance with professional rules and standards which are generally accepted in the international petroleum industry". The 2000 Ghanaian model Petroleum Agreement includes in Article 17 (which deals with "Inspection, Safety and Environmental Protection") at Article 17.2 that the oil company shall:

Whether or not the contract uses a longer or a shorter definition, as the text in bold indicates, they all, to some degree or another, refer to something that is accepted within the industry. This begs the next question which is what can be considered to be generally accepted. This is dealt with in the next chapter.

21. Operational Etiquette

Petroleum contracts are full of requirements for the oil company to conduct its operations in accordance with 'petroleum industry good practice' or 'accepted standards' as laid out in the earlier section. But what are these good practice and standards? Good question. Contracts hardly ever specify the practice or standard the company needs to adhere to, so how do you know which one to apply? Well, you don't in fact. Isn't that helpful? Its a bit like not knowing the etiquette or behaviour required in a particular social situation - what one person may consider appropriate may outrage another.

The question or assumption of the parties as to which standards and practice (or etiquette) apply is very often a point of dispute well after the contract has been signed, exactly because the contract does not specify the applicable practice. The difference in accepted practice between the parties has proven to be problematic particularly where new industry players or non- traditional companies are involved. Even though hardly any contracts currently do it, it would be advisable to spell out the applicable practice or standards.

As noted in the section above, most contracts state that the company has to adhere to national legislation (sometimes the specific laws are defined and other times they are not) as well as apply petroleum industry good or accepted practice. Some contracts then continue stating that the most stringent requirements should be applied, without stating which standard or practice is the most stringent. In the event that there is no section of the contract specifically addressing the environment, generic obligations to comply with "applicable laws" and "industry standards" may nonetheless be found in a section that lists out generally the obligations of the oil company.

This section provides an overview of associations and groups that recommend practice and provide standards on social, environmental, and health & safety issues. This might provide guidance for the inclusion of reference to specific practice or standards in contracts.

There are a number of industry associations that have developed best practice guidance addressing health, safety, social and environmental issues. Petroleum companies can voluntarily join these associations and most of the major petroleum companies are members of these associations. Some of these associations are: the International Petroleum Industry Environmental Conservation Association (IPIECA), the American Petroleum Institute (API), and the International Oil and Gas Producers Association (OGP). The associations cover issues such as Biodiversity, Climate Change, Marine Environment, Decommissioning, Human Rights, Social Responsibility, and Water.

Besides these global petroleum associations there are several regional and national petroleum associations of which petroleum companies can be a member, such as ARPEL (Regional Association of Oil, Gas and Biofuels Sector Companies in Latin America and the Caribbeean) and APPEA (Australian Petroleum Production and Exploration Association). These cover similar ground in publishing good practice guidance on social and environmental sustainability issues. Companies often refer to the fact that they are following the guidance and standards provided by one or more of these associations on their website, often covered under the Health, Safety and Environment or Corporate Social Responsibility tab.

In addition, to these private secor associations there are also regional inter-governmental groupings such as the African Petroleum Producers’ Association (APPA). They serve as a platform for petroleum producing countries to cooperate, collaborate, share knowledge and competences, including on environmental and social matters. None of the guidance provided by these associations is mandatory for governments to follow.

The International Organisation for Standardization (ISO) has developed industry-wide standards on environmental management (ISO 14000) for controlling environmental impact and improving environmental performance. ISO 31000 provides standards on risk management. Companies can get certified for many ISO standards, including ISO 1400 and 31000. ISO standard 26000 provides guidance on social responsibility, although it does not provide the option for certification. ISO has a Technical Committee (TC67) specifically dedicated to setting standards for the petroleum industry regarding materials, equipment and structures used. TC67 has developed about 150 standards which are increasingly being taken up by the above mentioned associations. Again, these standards are voluntary and it is up to a company to adopt these standards and/or get certificied.

The Global Reporting Initiative provides a framework companies can use to report on economic, environmental, social and governance performance. The reporting framework is complemented by sector guidelines on oil & gas which covers:

• Local content
• Volume and characteristics of estimated proved reserves and production
• Renewable energy
• Assessment and monitoring of risks for ecosystem services
• Policies, programs and processes to involve indigenous communities 
• Existence of emergency preparedness programs
• Decommissioning of sites

The United Nations Global Compact have developed ten universally accepted principles from some of the key UN Conventions in the areas of human rights, labour, environment and anti-corruption. Companies can sign on to the UN Global Compact and will than need to report annually on the progress made in implementing these principles. Again, this is a voluntary initiative. Even though to date some 8700 businesses covering more than 130 countries apply the UN Global Compact principles, there is little participation from petroleum companies in this initiative.

The United Nations has also developed the United Nations Voluntary Principles on Security and Human Rights (UNVPs), which are increasingly referred to in natural resource contracts under clauses that discuss the provision of security for the project area. Companies often make use of private or public security forces to protect their operations. In some countries, especially conflict-affected ones, the use of security forces has led to alleged human rights abuses. The UNVPs guide companies in maintaining the safety and security of their operations while also ensuring the respect for human rights. The UNVPs require a risk assessment covering the identification of security risks, the potential for violence in the area, the human rights record of the state and its security forces, and an analysis of past or current conflict in the area. Guidance is also provided on the way in which companies can promote human rights compliance of public and private security forces.

Companies wanting to access funding from financial institutions will increasingly need to deliver on environmental and social sustainability standards. For instance, the International Finance Corporation (IFC) which is part of the World Bank Group has developed eight Performance Standards in the field of environment and sustainbility, which companies receiving funding from the IFC need to comply with. The IFC standards include requirements on developing social and environmental baseline and impact assessments as well as management plans, protecting indigenous peoples and cultural heritage, providing a safe working environment, land acquisition and resettlement, prevent pollution and use energy efficiently, and protect the health, safety and security of communities. These standards are increasingly also taken up by Regional Development Banks, such as the Inter-American Development Bank (IADB), African Development Bank (AfDB). The IFC Performance Standards are incorporated in the Equator Principles as well, which are applied by 75 privately owned financial institutions world-wide. A company wishing to access funding from these banks will need to demonstrate compliance with these standards.

There are separate standards for health and safety issues. The Oil Industry International Exploration and Production Forum, IPIECA, the International Association of Drilling Contractors, and the International Assocation of Geophysical Contractors are several examples of associations and groups that have developed standards for health and safety.

Rarely do contracts make reference to specific standards or good practice. One example is the Development and Production Sharing Agreement of the Gunashli field in Azerbijan, in which the annex refers to Health and Safety standards by stipulating that the contractor ...

The contract further states that the most appropriate standard relative to the Caspian Sea ecosystem should be applied.

22. Before you start

Either the contract or the environmental legislation will require the company to identify and adequately mitigate potential environmental (and social) impacts it might cause. In order to establish the environmental (and social) conditions prevalent before any field work started, the environmental and social risks of the petroleum project, and how these risks can be managed, the company should be required to submit several documents that require the approval of the government department or agency responsible for environment. Social risks and impacts are still relatively new and some countries and/or contracts do not incorporate this type of risk in the requirements for analysing potential impacts, even though operations can have transformational impacts on communities. International standards do require social issues to be incorporated, and several environmental laws mention social issues as part of the requirements. Usually, approval of at least one of these documents (the baseline assessment) has to be granted before the company can start any field work. The documents include:

The requirement to conduct a Baseline Assessment is sometimes mentioned separately in either the contract or the environmental legislation, and other times it is listed as part of the required environmental impact assessment (such as under international standards). Sometimes a baseline assessment is not required at all. Ideally, baseline assessments should be conducted before any field work has started. Sometimes, however, the contract only requires a baseline to conducted together with the impact assessment at the point where a commercial discovery is made and the company is already preparing for field development and production. Some examples are shown below.

The content of the baseline study is then described in the Appendix of the contract.

The content of the environmental impact assessment is usually defined in the environmental legislation. If it isn't, or no environmental legislation exists, the contract should include information on the content of an environmental impact assessment. For example, the Agreement for the Azeri and Chirag fields in Azerbaijan lists the required content of the baseline and impact assessments at Appendix 9. Alternatively, a contract can refer to international standards such as those set by the Global Oil and Gas Industry Association for Environmental and Social Issues (IPIECA) and the Performance Standards of the International Finance Corporation (IFC), which include requirements for the content of social and environmental impact assessments. The impact assessment should be completed as early in the project cycle as possible, but in any case before the development phase starts.

Because of their high-risk nature, impact assessments for petroleum projects should consider all relevant social and environmental risks and impacts. This includes impacts on the following:

• Livelihoods and incomes of affected communities within the project area
• Flora, fauna, and biodiversity, both onshore and offshore (if applicable)
• Loss of access to land and sea by communities
• Community health and safety
• Security issues
• Labor
• Effects on hunting/fishing yields
• Disturbances caused by high noise levels
• Biodiversity
• Air/water quality
• Conflict and Human Rights
• Land Acquisition 
• Resettlement and compensation
• Cultural Heritage

Another important and related aspect here is the one on land. Procedures for acquiring land to conduct operations are usually covered in separate laws or in the petroleum project under clauses titled "Occupation of Land" or "Land Acquisition", or similar titles. The government is responsible for handing over government-owned land to the company, and the company is usually responsible for resettlement processes or compensation required for privately owned land, although some contracts state involvement of the government in clearing privately-owned land as well. The costs a company might incur in the compensation and resettlement process are sometimes made recoverable. In many developing countries land ownership is a sensitive issue and land titles are not well documented. This often leads to problems and delays in the land acquisition process, and can cause severe grievances at the community level if not well handled. International standards such as the IFC Performance Standards and World Bank Operation Policy 4.12 cover resettlement and compensation as well.

The Ghana Deepwater Tano contract does not include much detail on assessments and management plans because these issues, including social aspects, are covered in the Environmental Act. It does make a reference to management plans at Article 17.3:

Sometimes, usually in countries where there is no separate government entity responsible for environmental issues, the management plan is included in the field development plan so that approval of the Ministry of Petroleum or the National Oil Company is required. Occasionally, the contract requires the management plan to be included in the Annual Work Plan, so that approval of the government or joint management committee is required. Annual reports on environmental impacts and management are usually required to be submitted for review by the company to the responsible government agency.

In the example below from Azerbaijan, the national petroleum company is involved in selecting the consulting firm that will conduct the impact assessment. It will also have a direct involvement in the study:

If there isn't an environmental law and specific government entity responsible for environmental issues, often the National Petroleum Company or the petroleum ministry is responsible for approving (instead of issuing a permit) the environmental assessment and management plans proposed by the company. In the Production Sharing Contract of Azerbaijan, the contractor, together with the National Petroleum Company prepares an environmental baseline and impact assessment. A sub-committee responsible for handling environmental issues under the Joint Management Committee then designs an annual monitoring program and reviews its results.

International good practice and legislation in some countries do not only address the required content of impact assessments, they also require a certain level of community consultations to be part of the process by which impacts are determined. This is often the only chance the affected communities have to provide input into the process and project. The requirements regarding the depth and usefulness of these community consultations are often debated. It often remains unclear if communities have had a real voice in the process, whether they are adequately represented, and if their concerns are incorporated the company's assessment and management plans. Some International good practices include 'Free, Prior, and Informed Consent' (FPIC) as a prerequisite for the start of petroleum operations, meaning that affected communities have to have had sufficient time in advance to consider the impacts the operation might have on them, and that they have given their consent for the project to start. Even though FPIC is required by international standards such as the IFC Performance Standards, the term or requirement is usually not included in the petroleum contract and/or law.

23. When things go wrong

If things go wrong and the petroleum operations cause harm to the environment, people or property, who is responsible for fixing it? And who pays for it?

In terms of responsibility, the contractor is primarily responsible for the conduct of petroleum operations. Without a petroleum contract saying any more, this responsibility should extend to activities necessary to mitigate or resolve environmental damage or harm to people or property. There will likely be laws that address the requirement for the company causing the damage or harm to restore the damage done and/or compensate those who have suffered. The general obligations in the contract will state that the company needs to comply with applicable law or perform petroleum operations in accordance with industry standards or best practice. This will import the obligation to comply with those environmental or health and safety laws or standards or best practices insofar as they require mitigation or re-mediation steps to be taken. The contract may have provisions that set out the responsibility of the oil company in case of damage or harm. For example, in the Iraq model Technical Service Contract, Article 41.11(a) states that:

In the Ghanaian 2000 model form Petroleum Agreement, Article 17.5 states that:

As has been previously discussed, the requirement to take actions in accordance with, in the above examples, "Best International Petroleum Industry Practices" and "accepted Petroleum industry practice" raises some questions as to exactly what the oil company needs to do to fulfil its obligations to remedy damage or harm but the contract does settle the responsibility on the oil company to take action.

So who pays for the measures taken? In short who ultimately bears the costs incurred resulting from an accident.

The costs for measures taken to resolve damage or harm done fall under the costs of the general petroleum operations. An oil company will typically recover the costs resulting from an accident through its petroleum operations in one way or another. This takes different forms depending on the type of contract.

In a concession contract, such costs will be deductible from revenues from petroleum sales for the purposes of determining taxable profits. In a production sharing contract, the oil company will be entitled to a share of produced petroleum to recover its costs. In a service contract, the fee paid to the oil company will include a component to cover its costs.

If the oil company is ultimately reimbursed for the costs it incurs to mitigate any damage caused or harm done, one perspective is that the oil company does not directly or fully, pay for the mitigation or re-mediation activities. To the extent that the costs reimbursed represents revenue that the State would otherwise have received. It may be said that the state indirectly pays for such measures, or that the state and the oil company share the costs since expenditures reduce revenue available to both parties.

The principle that costs incurred in mitigation or remediation of environmental damage or harm to people or property are petroleum costs that are recoverable is often expressly stated in the petroleum contract. For example, the Iraqi model Technical Service Contract Article 41.15 provides that:

However, petroleum contracts often contain one important qualification or exception to the principle that such costs are treated as petroleum costs. This is illustrated by looking at the full text of Article 41.15 of the Iraqi Model Service Contract which states as follows:

"Except for cases of Gross Negligence and Wilful Misconduct on the part of the Contractor and/or Operator, all costs incurred towards the protection of or damage to the environment shall be treated as Petroleum Costs".

This qualification or exception is also illustrated by the Ghanaian 2000 model Petroleum Agreement in which the last sentence of Article 17.5 states that:

So, where pollution or damage results from the "gross negligence" or "wilful misconduct" of the Contractor the costs are not petroleum costs but are paid by the contractor (the oil company) itself. The question then becomes: What is "gross negligence" or "wilful misconduct"?

This is a complex area of law to which there is no easy or single answer. The definition of what constitutes "gross negligence" or "wilful misconduct" may vary from country to country and depends on the law that governs the particular petroleum contract. The basic principle is however, that for the oil company to bear the costs itself its behaviour must have fallen significantly short of the standard expected or required by the petroleum contract or law. A mere mistake will not constitute "gross negligence" or "wilful misconduct". The fact that the negligence has to be "gross" and the misconduct "wilful" makes it apparent that not just any negligence or misconduct by the oil company will be sufficient to make it bear the costs itself.

In the event of a significant or catastrophic environmental mishap or accident this question will be of commensurately significant importance. An example of this is the 2010 Deepwater Horizon/Macondo spill in the Gulf of Mexico. The critical question in relation to the potential liability of the companies involved in the accident was/is whether they were "grossly negligent" or not.

How does the petroleum contract help ensure that the costs for mitigation and restoration are met? Petroleum contracts will contain provisions that require the oil company to take out necessary insurances. This obligation may be a very general one, such as an obligation to take out insurances that shall "cover the types of exposure that are normally covered in the international petroleum industry". Sometimes contracts state more specific types of required insurance cover such as "including but not limited to damage to equipment, installations and third party liabilities". It is rare to find a requirement that expressly requires an oil company to have environmental insurance. On such example where this is the case is the Brazilian Concession Agreement which states that:

Insurance covering environmental damage reduces the financial risks to which the state and company are exposed. But this assumes that such insurance is available. The challenge here is that since the Gulf of Mexico oil spill in 2010 it is increasingly difficult to identify insurance companies willing to insure petroleum companies for these types of environmental risks, as they are difficult to evaluate and estimate. 

Whether or not insurance cover is available, if the oil company is a small company without significant assets or balance sheet strength, or a small subsidiary of a big oil company, the petroleum contract might include other ways of ensuring that the oil company can meet and pay for its obligations under the petroleum contract generally, including environmental damage or harm done.

Petroleum contracts therefore often require that a formal guarantee is provided by a parent company of the oil company, or from a financial institution. So, for example, if a major international oil company forms a local company to enter into a petroleum contract, the government of the host-country will in some instances require that the international oil company guarantees the performance and obligations of the local oil company. If the local oil company cannot pay the costs it has to pay in case of environmental damage or harm caused, the government can require that the international oil company pays for it, by including a parent company guarantee. Then only if the costs are too great for even the international oil company to cover and it goes bankrupt as a result, then the government is left to pick up the pieces and meet the costs.

24. Cleaning up

Eventually an oil or gas field will come to the end of its economic life, meaning that it is no longer profitable to continue producing oil or gas from the field (cf. the first section to read more about the life cycle). At that point an oil company is typically required to "decommission" or "abandon" the field. The use of the term "abandon" is a misnomer since the obligations of the oil company are not at all to simply walk away from the field. In fact, quite the reverse. The obligation of the oil company is to remove the facilities and infrastructure that it built for the purposes of producing and transporting the oil or gas and, so far as possible, to return the natural environment to the state it was in before petroleum operations commenced. Accordingly, most contracts and participants in the oil and gas industry now refer to "decommissioning" rather than "abandonment" although the two terms refer to the same thing.

At the time that a petroleum contract is entered into the issue of decommissioning may not be at the forefront of the parties' minds, since such activities may not be relevant for another twenty to thirty years (depending on the length of the contract and the success or not in finding commercial quantities of oil and/or gas). Additionally, in any new oil and gas producing jurisdiction the issue of decommissioning is understandably not a major preoccupation as opposed to the business of stimulating exploration and getting to production. One might compare, for example, the early stage oil and gas industry in Ghana or Uganda with the very mature industry in the United Kingdom. There are over 500 platforms with associated pipelines and other infrastructure in the United Kingdom, the cost of removing which has been put by Oil & Gas UK at over £28.7 billion by 2040. A petroleum contract and/or related legislation needs to provide for the obligation to decommission an oil or gas field, the cost of which may be significant, particularly in relation to an offshore oil or gas field.

With such high costs, a key concern related to an obligation to decommission an oil or gas field is to ensure that the oil company is able to pay for it. By definition, this process of decommissioning comes at a point in time when an oil company is no longer making any significant profit from the field. Accordingly, the costs of decommissioning cannot be met from the revenue that is generated from the sale of oil or gas from the field. So how does the Government ensure that decommissioning activities will be paid for? The mechanism that has been developed and is typically used to deal with this is to ensure that, from a certain point in time during the life of the oil or gas field, the oil company starts contributing to a fund which will accumulate and, a the end of the life of the field, be available to pay for the cost of decommissioning. These contributions are made whilst the oil company is generating a profit from the field and can afford to put money aside to meet the future costs. To determine how much money needs to be put in this fund, the oil company will need to prepare a decommissioning plan which will set out the activities that need to be undertaken to decommission the relevant field and the estimated costs of those activities. By updating the plan on a regular (perhaps annual) basis, the estimated costs are kept current. In some jurisdictions, instead of putting cash into a fund, an oil company may be able to provide security for its financial obligations in relation to decommissioning, such as a bank letter of credit.

As with other matters relating to the environment, there are wide divergences in the degree to which petroleum contracts expressly deal with this issue of decommissioning. The Ghanaian model Petroleum Agreement at Article 17.3 merely provides that the oil company will:

The Iraqi model TSC is similarly brief, providing at Article 42 that the oil company prepares a proposal for approval relating to site restoration and decommissioning"around mid-Term" and on expiry or termination of the contract it shall:

In neither case is there any mention in the contract of a requirement to set aside monies in a decommissioning fund although this may be a required feature of any decommissioning plan agreed in the the case of the Iraqi TSC.

By contrast, the Kenyan model PSC includes at Article 42 some four and a half pages of provisions relating to abandonment and decommissioning including a requirement to submit a "Decommissioning Plan" as part of the Development Plan, a requirement to, from a certain point in time:

The amounts accrued must be paid into a separate interest bearing account to ensure that they are available to pay for decommissioning activities. The oil company is entitled to recover amounts that it sets aside as petroleum costs. Likewise Clause 38 of the Kurdistan 2012 model PSC has relatively extensive provisions relating to decommissioning obligations including a requirement to:

25. Dealing with differences

If one thing is certain about a petroleum contract it is that, at some point, the two parties will disagree. The disagreement may be about whether they have done what they said they would in the way they promised to and within the time-frame they agreed on.

Sometimes, before the parties can decide whether or not one of them has not done what they said they would do, they may have an argument over the interpretation of the relevant provision of the contract! Notwithstanding all the time and effort put into negotiating and writing the contract there is always scope for disagreement about what particular provisions actually mean. In fact, an important fact about petroleum contracts that may come as a surprise to outsiders is how often they include provisions to negotiate one matter or the other at some later stage.

"Good faith" seems to be a critical wording here. And an example of phrases that postpone a decision (cf. examples below).

In our family of contracts, we have for example:

With the contract comes an appendix of Accounting Procedures referred to in the main contract.

and another example from Iraq

Sometimes, then, on major issues, the contract states an agreement to agree at a later date, with the explanation that "We haven't got the information to discuss this now". A good example is gas, what to do with unknown reservoirs the company might stumble across when exploring for oil. Other times, an ambiguity is left deliberately in a particular provision as the only way to reach agreement of all parties in a given time frame - "We can't resolve this completely now so let's use placeholder language". In such cases each party might give its own meaning to the clauses, different to the other side's, and they may or may not be aware that the other party's interpretation of that clause is different.

This clearly involves a risk of disagreement and dispute at some point in time.

Another phrase frequently used in contracts but which can set the parties up for disagreement, is an obligation to "use reasonable efforts" or to "deliver in a timely manner" to do something. Although the law may provide some guidance as to what "reasonable efforts" or "deliver in a timely manner" requires, there will, in any given situation, be scope for argument as to whether what has been done constitutes "reasonable efforts" or "timely manner". Then again there are references to "generally accepted international practices".

Many contracts stipulate that contracts need to be "prudent" and "diligent". Of our family of contracts, six (Azerbaijan, Brazil, Indonesia, Iraq, Libya and Timor Leste) present 25 uses of the word "diligent" and eight of the word "prudent". It is left to courts to decide what meaning should be attached to words which, to the outsider, look nebulous and subjective.

Generally, disputes arise when one party's interpretation of a provision results in the other party having to spend more money or get less money than it believes it should do, or where one party believes that the other's interpretations or actions deprives it of a significant benefit or right that it was entitled to.

The petroleum contract will always have a section that sets out the rules for how the parties will resolve or settle disagreements. This might be referred to as the "Dispute Resolution" section or as the "Arbitration" section or something similar. There are a number of different mechanisms available to resolve contractual disputes, including:

• parties reaching agreement on the resolution themselves
• using a formal mediation process
• engaging an expert to make a determination of the issue in dispute
• legal adjudication of the dispute/arbitration

Sometimes a contract may include all of these processes in a hierarchy starting with an obligation for the parties to try to reach an agreement themselves and ending with submission to the relevant legal adjudication process.  In the example below, a hierarchy is provided as follows,

In almost all cases, the parties will as a matter of common sense try to resolve disputes themselves first, irrespective of whether or not the the contract requires them to do so. It's far cheaper and less prejudicial to the relationship than calling in outsiders. It is only when that appears to be impossible that there arises need to resort to the other dispute resolution mechanisms. Certain disputes that are of a more objective nature lend themselves to expert determination, for example around the valuation of oil, where clear data are available from markets, and other accounting matters. The contract may specify the appointment of an expert for some issues which will typically be of a technical nature and therefore suitable for objective, expert determination. Disputes that involve subjective issues of interpretation of the meaning of parts of the contract are not suitable for expert determination.

The issue of where an arbitration takes place is naturally sensitive. Media and the public in host countries often feel that the shift in jurisdiction away from their country is an affront. But companies worry that the court system of their government partner may be subject to political pressure. However it is important to understand that the fact that the arbitration is taking place out of the country is separate from the question of which country's law will be used. So, if a dispute arises under a petroleum contract in Ghana, then Ghanaian law applies to the contract, and an arbitration process would decide the dispute applying Ghanaian law even if the arbitration process is carried out in a different country. The arbitration process being carried out in a different country is seen as a neutral or fair process by the oil company compared to settling the dispute in the Ghanaian courts.

Whilst host country citizens may find the suggestion that their courts are not impartial or fair somewhat insulting, the reality is that in many jurisdictions the court process may not be independent, or may be slow, and international investors generally (not just oil companies) prefer not to take that risk.

Typical features of an arbitration provision in a contract are:

• Provision that the arbitration be conducted in accordance with the rules of a particular arbitration organisation. There are a number of recognised international arbitration organisations each of which have a set of rules that will apply to the arbitration process. Different rules have certain pros and cons, an examination of which is beyond the scope of this book, but the better known and often used ones include the UNCITRAL Rules, the London Court of International Arbitration Rules ("LCIA"), the International Chamber of Commerce Rules ("ICC") and the rules of the International Centre for Settlement of Investment Disputes ("ICSID");
• Provision of where the arbitration is to take place. This might be referred to as the "seat" of the arbitration. Often, a "neutral" venue is chosen, being one that is not in the country with which the contract is made and not in the country from which the relevant oil company or its parent organisation comes from. Choices of independent venues might include, for example, Paris, London or Stockholm. It is important to note that this does not mean that French, English or Swedish law will be applied to the dispute instead of the relevant governing law of the contract. Sometimes the chosen venue is indeed located in the country where the oil company or its parent comes from. For example, the recent arbitration involving the Government of Uganda and Heritage Oil, a London head-quartered and listed company was being conducted in London, the location specified by the relevant petroleum contract;
• Provision on the number of arbitrators that will determine the dispute. Frequently this will be three. This allows each party to select one arbitrator and then to jointly appoint a third or for the third to be appointed pursuant to the relevant arbitration rules. Although all of the arbitrators should be impartial and objective, if only one arbitrator is used there is a greater potential for one party to feel that the arbitration process is not fair;
• Provision for the language in which the arbitration should be conducted, which would normally be a major international language that has some (historical) relationship to the country to which the dispute relates such as English, French, Spanish or Portuguese.
• Provision on who pays for the arbitration. Usually the expenses of an arbitration are borne equally among the Parties.

Looking at the contracts that have been used to provide examples in this book and how they deal with dispute resolution we find that they all refer disputes that cannot be otherwise settled to arbitration and have arbitration provisions as follows:

The governing law clause in Azerbaijan states:

26. Stabilisation

Stabilisation, the provisions that international companies use to secure guarantees against changes in the conditions or the investment environment within which a contract was negotiated, is an issue sure to provoke heated debates whenever included in investment agreements. Petroleum contracts are no exception.

Governments can rise or fall through elections, or even revolutions, society and economic development needs and the legal environment can change fundamentally, as well as the international context. The company therefore endeavours to "stabliise" the terms of its investment by writing into the contract provisions which prevent overall changes in the legal, financial, environmental and social requirements in the country of operations from affecting their operations. Breaching that provision then, will entitle the company to usually generous compensation.

Countries, of course, see it completely differently, more like an infringement of sovereignty. A stabilisation provision in a petroleum contract should therefore never actually have the effect of preventing changed laws of the country from applying to the contract. However such changes in a country's laws may have an adverse effect on the economics and profitability of the project, and since nobody can challenge a sovereign country's rights to change its laws at any time, the company is in a general sense always at a possible disadvantage in what is for them a commercial relationship with a commercial counrterpart.

What a stabilisation clause in a contract might say, then, is if the country changed its laws in a way that affects the relevant petroleum contract, this would be a breach of the provision and give the oil company a right to claim compensation for such a breach. Alternatively, the changed laws will not apply to the contract.

No problem understanding why governments and citizens of oil producing countries don't like stabilisation clauses. From the government's perspective, an oil company investing in their country should take the risk of a change in law since setting its own laws is one of the fundamental rights of a sovereign state. For this reason, governments will resist an generic stabilization provision. In fact, whilst stabilization clauses exist in older petroleum contracts, they are becoming increasingly rare. These clauses are often referred to as "freezing clauses" because they freeze the law in place at the time the contract is signed.

The aim of an equilibrium provision is similar to a stabilisation provision, minus the political sting - to preserve the overall economic position of (typically) the oil company or (sometimes) the government without being seen to infringe sovereignty. The principle is that one of the parties is adversely impacted by a change in law, both parties seek to agree to changes to the petroleum contract that will restore the original financial position. The company gets the same reassurance but the locus of change has been moved inside the contract. The contract now sets up its own renegotiation on this issue given the recognised trigger, leaving the wider body of regulations and laws in the country out of the picture.

For example, if the country amends its tax law and taxes imposed on the profits of the oil company are increased by 10%, the parties would seek to agree an amendment to some other terms of the petroleum contract to compensate the oil company for the increased tax it has to pay, for example, by increasing the profit oil it receives or a reduction in the royalty rate. There might still be haggling over the numbers, since, as we have seen, each fiscal tool has its own properties. You can adjust a royalty rate to exactly compensate for a rise in corporate tax at a certain price point of crude oil, for example, but you may lose that correspondence if prices move up and down. But this is technical quibbling (lawyers yammering on?) at the margins. The essential sting of the change in law will have been removed for the company.

So the parties agree to renegotiate. But if they can't agree an amendment to the contract, then the equilibrium clause may provide a basis for the oil company to seek compensation. In this case the ultimate effect may be similar to that of a stabilisation provision as described above.

Note: Equilibrium clauses are often quite short. That doesn't mean that they are not important.

Some examples include:

Look closely and you will see that the second example offers the oil company less protection than the first. The first example applies to "any change in the provisions of any Law" which "adversely affects [any of] the obligations, rights" of both parties. This kind of broad and generic language is sometimes referred to as a "freezing" clause.The second example applies only if the change in Law "adversely and substantially" affects the "financial interests" only of the contractor. The burden of proof is higher. In addition the stabilisation is confined to what may produce a change in financial interests only.

Civil society groups sometimes complain about freezing clauses as in the first example above, on the grounds that such a clause can have an impact on a government's room to pass new social and environmental laws, for example on health and safety, labour and employment rights, the protection of the environment and cultural heritage, and human rights. From a lawyer's perspective the difference between the two clauses may not be as great as it appears at first glance, since even with a more restricted clause such as in the second example a company could argue that stricter or more comprehensive social and environmental laws result in a higher cost of compliance. If, on the other hand, the contract at its inception required the company to apply international practice or standards for its social and environmental practices, then a stabilisation or equilibrium clause would not apply unless new social and environmental laws were passed which are more stringent than international best practice. The country would then have assured itself a floor of compliance across a range of issues without the concern of triggering these clauses.

Some jurisdictions, like Libya, don't offer any form of stabilisation or equilibrium clause, and there's even one example where an "anti-stabilization" clause is included in a model petroleum contract:

On a final note, stabilisation or equilibrium provisions may not always be in a clause conveniently labelled "Stabilisation" or "Equilibrium". In the family of contracts used in this book, for example, Azerbaijan has a clause (23) called "Applicable Law, Economic Stabilisation and Arbitration", while in Ghana it slips in under Article 26.4 "Miscellaneous". Other contracts have references to the principle scattered across the contract, in clauses dealing with governing law, dispute resolution or miscellaneous provisions or even in environmental, tax or subject specific provisions.

Often but not always towards the end of the contract.

Happy hunting!

27. Confidentiality

Let us go back to where we began.  This book aims to describe oil contracts, the issues they govern, the history that shapes them and the world they live in, in broadly neutral terms. We see a value in explaining without taking sides. The one exception to that neutrality is contract transparency. This book actively seeks to promote contract transparency as an emerging norm which will improve governance of the oil and gas industry around the world. Let us now explain why, taking a look at the confidentiality clauses themselves in the contracts.

Opponents of contract transparency advance two main arguments. First, that contracts as currently written forbid it. And second, that it would harm their interests. Let's take each of those in turn.

Every contract we feature in the book deals with the issue of what can be published and what can't - who can release what information under what conditions. And some of them seem quite restrictive. Some examples:

Heavy! Except for notice that the restrictions apply to "information and data" and do not explicitly mention the contract itself. Is the contract part of such data and information? Some contracts do specify that, but most don't. Opponents of contract transparency often argue that the provisions of contracts themselves prevent publication but we can see from the actual wording that this is, at the very least, open to interpretation. Terabytes of information are generated during the lifetime of a petroleum project these days, from seismic data and interpretation at the exploration stage to core samples and analysis from drilling, to well logs and trading data generated by getting the stuff out of the ground and selling it. This is more clearly data and information defined in these clauses rather than the contract itself.

But in addition, all these articles then go on to specify permitted exceptions to the rule of secrecy. These typically are when information is already in the public domain or there is a dispute which has gone to arbitration. Or when (as in the case of Ghana) the state oil company wants to brief any consultant, or to attract other investors to nearby areas, or the company needs a bank loan or for another financial transaction. And in fact this is what happened in the case of the Ghana contract which is a final, signed and initialled agreement you can find on the Internet.

Other agreements start to differentiate between the obligations of the companies and those of the state. Back in 2001, for example, Brazil's modern concession agreement imposes the strictest of terms on the company.

The obligations on the Brazilian government, as represented by ANP, are somewhat more relaxed:

So while the company should "never" disclose anything "for any reason whatsoever" ANP can disclose anything to comply with the purposes for which it was. That's a pretty broad exception.

Libya's EPSA IV agreements of 2005 have a long clause relating to confidentiality - but every provision applies to the "Second Party" - the company. The "First Party", the government of Libya as represented by the National Oil Corporation, has no obligations whatsoever stated in the contract.

Finally, Afghanistan's agreement with CNPC in 2011 is the only contract in the suite which doesn't have a confidentality clause. Instead it has a transparency clause.

Following this, it has a "Trade Secrets" clause:

So the principle is established the other way round. Everything should be public, unless a specific reason is stated as to why it should be private.

This is as it should be. It also conforms to the emerging norms of freedom to information legislation which have been passed to provide access for citizens to information held by the state in 90 countries out of the 196 official independent countries of the world.

As can be seen from the contracts profile, though, many contracts have been published in their final form - Ghana's agreement with Tullow, Timor Leste's with Eni, Azerbaijan's with BP, and Afghanistan's with CNPC. Nothing dramatic has happened.

The other thing is that many more contracts are published already - in high cost commercial databases used within the industry. Some of the writers of this book have access to those databases which contain hundreds of contracts that are still considered to be "secret". Companies may be worried about commercial competition gaining access to sensitive information - but the most widely stated objections to confidentiality clauses involve the case of a state wanting to attract other investors to other blocks - their competitors precisely. But it is in fact commercial competitors who have most access to these contracts in the first place.

28. Glossary