Changing fiscal landscape
* Daniel Johnston is founder of Daniel Johnston & Co., Inc a financial consulting firm to the international oil industry. Daniel is author of a number of books on the subject of petroleum fiscal analysis and design. E-mail: daniel{at}danieljohnston.com, dj_co{at}msn.com, www.danieljohnston.com
Oil company and government relationships at the turn of this century are under intense pressure. These relationships are always in a state-of-flux but higher drama now exists in the heat of the current price shock. Just as the aftermath of the 1973 embargo has undergone nearly constant re-examination over the years, the dynamics of today’s industry will be reviewed and studied for generations. This is true for a number of reasons but particularly because governments are reconsidering their position with respect to their oil industry partners and many are taking action.
Sometimes sorting out cause and effect is like chasing one’s tail. The dynamics are complex and fundamentals do not always provide the answers. The changing landscape is due to a number of things aside from this price shock, but the focus here is the future of the relationships between oil companies and governments.
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1. IOCs–NOCs – Service companies |
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What was once the exclusive domain of the major international oil companies (majors) has become intensely competitive. Independent oil companies (independents), national oil companies (NOCs) and service companies are all encroaching upon the traditional domains of the majors. The major oil companies still have an edge in deepwater and frontier regions and with mega-projects, but even these areas are no longer exclusively theirs.
It is often said that oil companies’ main contributions are capital and technology. Furthermore, companies typically have taken upon themselves the lion’s share of the risk associated with exploration. These were the main reasons why governments brought in outside companies to explore for, develop and produce hydrocarbons (instead of doing it themselves).
To say that oil companies provide capital and technology is an over-simplification. Actually, to a large extent companies provide a service of ‘procurement’ for and on behalf of governments and themselves for both capital and much of the technology. While companies still possess impressive geological and geophysical (G&G) talent and the ability to orchestrate large-scale international projects, they must still procure much of what is needed to conduct petroleum operations. For example, it is widely known that drilling technology is highly evolved and in many circumstances (particularly deepwater and harsh frontier environments) it is virtually ‘space-age’ technology. Yet, most oil companies do not own drilling rigs.
Thus, much of today’s technology is field-proven, off-the-shelf technology available on a global scale to major oil companies, independent oil companies and NOCs alike. Also, many governments no longer feel the burning need for outside capital.1,2
Independent oil companies
The first inroads into the domain of the major oil companies came from the independent oil companies. This occurred in a significant way in Venezuela in 1956 and in Libya in the early 1960s.3 It is significant too that the first of what are considered the modern production sharing contracts (PSCs) in Indonesia were signed by a consortium of independent American companies – the Independent Indonesian American Petroleum Company (IIAPCO) in 1966 and 1968.4,5 Even before the embargo in 1973 the independents were drilling over 30 per cent of the wildcat wells in the Gulf of Mexico (GOM).6 Today independent oil companies are responsible for most of the drilling, reserve additions, recorded discoveries and platform installations in the GOM shelf.7 While the smaller independent companies have encroached on the historical domain of the majors they also play an important role and have a symbiotic relationship with the majors and the NOCs. They are the ones the independents turn to when they make large discoveries and need to raise significant additional capital.
National oil companies
There are two dimensions to the growing influence of the NOCs. In the first instance, their strength in their home country reduces the influence and desire for outside oil companies. Second, expansion overseas by the state-owned (or partially state-owned) NOCs has become commonplace.
The encroachment of the NOCs started with the likes of Oman Oil Company, Malaysia’s Petronas and Brazil’s Petrobras. The NOCs joining the expanding list include, Sonatrach (Algeria), Statoil and Norsk Hydro (Norway), CNOOC and Sinopec (China), ONGC (India), EGPC (Egypt), TPAO (Turkey), Rosneft and Gazprom (Russia), Kufpec (Kuwait), ENI (Italy), CPC (Taiwan), Nippon Oil (Japan) and ADNOC (Abu Dhabi).
Now, 77 per cent or more of the world’s oil reserves are under the control of the NOCs and there are 13 NOCs each with more reserves than ExxonMobil, the largest of all the IOCs.8,9,10,11
In terms of financial muscle and technical competence the IOC/NOC playing field has been leveled significantly.12 Many NOCs are now extensions of their nation’s foreign policy – a position once held by many of the majors. The NOCs also have a competitive advantage because many governments prefer anything other than a Western major these days.
Service companies
The notion of using service companies instead of oil companies is not a new one. It was a hot and contentious topic in the late 1990s and is surfacing again with renewed vigour.
Governments can work directly with a service company but then the ordinary and important means of procuring goods and services through tendering is sidelined – the service company does not want to ‘tender’ for goods and services it already provides. If a government wants to deal directly with a service company, an ordinary fiscal structure, so common to most arrangements between governments and oil companies, would not be appropriate. A ‘fee-based’ system is best when governments intend to work directly with a service company. However, fee-based systems also work with oil companies. The Iranian buy-backs first signed in 1998 with Total for the Sirri A and E field developments have more of the characteristics of an engineering, procurement and construction (EPC) agreement – clearly the realm of service companies. The differences between oil companies and service companies have become blurred over the years.
The Schlumberger’s Integrated Project Management (IPM) unit, based outside London, conducts drilling and production operations. Like the majors, IPM is willing to assume more risk in the hopes of reaping greater rewards, but unlike most oil companies it is not concerned about ‘booking barrels’.13
In 2003, IPM worked out a profit-sharing arrangement with Shell and Petronas, Malaysia’s national oil company. Schlumberger agreed to redevelop and manage Bokor, a Malaysian field where output was declining. It boosted production by 40 per cent and received a share of the increase.
Schlumberger has also formed partnerships with Romania’s Romgaz at the Laslau Mare field in Transylvania and various projects with Pemex in Mexico. Partnerships such as these now account for about a quarter of IPM’s revenues, and it expects this figure to grow.14
These are unusual and frustrating times for the majors. With the confluence of so much competition, dwindling prospectivity in most non-frontier basins and rampant nationalistic and/or fiscal pressures, they are having an identity crisis.15,16
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2. Historical setting |
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Governments have always been interested in controlling their natural resources and by the early 1970s oil producing countries were better able to exert some control. On 22 January 1971, OPEC’s ‘General Agreement on Participation’ called for members to acquire a ‘sensible’ level of participation in oil operations starting with 25 per cent increasing gradually to 51 per cent.17
The early 1970s marked a sea change for the oil industry, from a buyer’s to a seller’s market and OPEC was starting to gain prominence. The early 1970s were marked by OPEC’s struggle with the industry, which was not so much about prices or revenue, but control.18
The reasons for increasing government participation included the need to gain control over a vital industry in order to enhance national security, obtain greater financial return and gain experience. Although the OPEC nations managed to establish greater control during the early 1770s, it was a struggle.
System evolution and government control – Indonesia
In light of the nationalistic mood of the 1970s, oil producing nations viewed existing concessions (royalty/tax systems) as remnants of colonial times. Gaining control over their natural resources required different contracts and terms. Indonesia’s PSCs provided significantly greater government control, but it was a long road.
The Indonesian constitution mandated that ‘natural riches be controlled by the State.’19 In the mid-1960s, Indonesia introduced Contracts of Work (COWs), which possessed much of the terminology and mechanics of later PSCs but it soon became clear that little if anything had really changed. ‘The worst aspect of the COW was the stonewalling by the Contractors of the relevant Government agencies when the latter attempted to learn the business’. General Ibnu Sutowo, then Minister of Oil said, ‘COWs are just concessions with a new suit on’.20
With the high prices following the 1973 embargo, exporting countries’ per-barrel revenues increased but the company revenues increased even more. This was in sharp contrast to the objectives and ideology of the exporters. Prices were too high for the Tehran and Tripoli agreements to survive because the agreements in effect provided governments with fixed per-barrel payments regardless of the actual market price.
The price system based on the 1971 Tehran Agreement was ‘out of whack’ according to Saudi Oil Minister Sheik Yamani.21 The companies’ part of the pie was supposed to decline, not grow. Companies were making record profits, but events were to prove that the penalty for badly structured agreements is death.22 This though is heavily one-sided, only governments have the power to impose the death penalty on a contract.
Conditions in today’s industry are similar to the aftermath of the 1973 oil embargo in many ways. Just as back then, changes in the fiscal/contractual terms worldwide are being imposed on the industry but in some cases the change is self-inflicted.
Contracts and agreements have continuously evolved in the 35 years since the embargo and these are more sophisticated now. However, the dynamics are similar and there is heavy pressure and action on many fronts. Many governments are reflecting on the past and the nature of their contracts/fiscal terms. The challenge is: How can we learn from the past and prepare for the future?
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3. Contracts of the 1980s–1990s |
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For all practical purposes the universe of fiscal terms that existed at the turn of the century (during the late 1990s and early 2000s) was the result of the multitude of systems and contracts legislated, negotiated, bid, signed and renegotiated during the 1980s and 1990s. During these years oil prices averaged around $18.00/BBL and approximately 90 per cent of the time ranged between $16.00/BBL and $20.00/BBL.
Key contract characteristics at the end of the 1990s:
- Average government take around 67 per cent.
- Average effective royalty rate of around 20 per cent.
- Numerous sliding scales based on production rates.
- Most systems are regressive.
- Most of the focus was on exploration contracts.
By the end of the 1990s it was clear that oil companies had been unsuccessful exploring for hydrocarbons during the 1980s and 1990s, and most governments were dissatisfied with the level of exploration and development activity in their countries.
While the amount of exploration acreage available worldwide has more than tripled in the past 20 years, there are also more companies seeking opportunities than ever before. From the point of view of most governments this is a healthy aspect of today’s environment. But it has not been healthy for most oil companies. For the past two decades the exploration end of the business has been notoriously unprofitable.23,24,25,26
During most of these two decades chronic over-bidding shaped the market for exploration acreage and projects.27 Bidding and/or negotiations in the industry have been strongly influenced by both increased competition and over-optimistic estimates of: oil prices, project costs and timing, prospect sizes and success ratios.
The average government take worldwide at the end of the 1990s was too high for ‘average’ geological potential (or prospectivity) at that time. For countries with better-than-average potential the government take was closer to 80 per cent. However, even better-than-average geological potential was rarely sufficient to sustain such a high government take.
Certainly many countries modified and/or improved their terms over the years particularly during the late 1990s, but relative to the dwindling prospectivity during these two decades, as geological basins matured and field-size distribution expectations declined, the fiscal improvements rarely kept pace.
This is not because greedy governments forced terms on an unwilling industry. Industry helped determine what the market could bear. Governments often had little choice than to allow a competitive marketplace to do its job.
The problem was that the market was more than competitive because of the natural optimistic nature of the industry explorers. Over-estimating reserve potential of an undrilled structure (a ‘prospect’) has been an extremely common problem in the industry.28,29,30 Postmortem analysis of the exploration portfolio performance of the 1980s and 1990s showed consistent over-optimism, particularly with two key variables: estimates of prospect size and success rates. For example, for any portfolio of prospects there is an average prospect size and there are associated estimates of success probability. However, typically and consistently actual exploration results were substantially less exciting than expectations in terms of success rates and discovery size. Actual success ratios were lower and the average discovery was smaller than expected.31 Unfortunately these over-expectations provided the basis for numerous bids and negotiations during these decades. This could not help but result in over-bidding and ultimately, loss of value. Most of this loss was from exploration.32,33 Similar conclusions existed and persisted for years in the US Federal Offshore.34,35 Then of course, the price increase changed everything.
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4. Prices and costs |
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The industry appears to have recognized that a sea change has taken place with respect to energy prices. While most believe the current high oil prices will not persist they do appear to believe in a long-term price of at least $50/BBL. The Energy Information Administration (EIA) forecast for West Texas Intermediate Crude for 2008 and 2009 is over $80/BBL.36 The EIA forecast has nearly doubled each year for the past two years.37
Most fiscal systems were not adequately constructed to efficiently handle such high prices because most systems are regressive – where the government percentage share of profits (take) goes down when the oil prices go up. This is one of the reasons why so many governments are changing their systems now.
Systems with well-crafted progressive sliding scales such as ‘R factors’, properly designed rate-of-return (ROR) features or price-cap formulas are usually progressive and have been under less pressure to change.
A common symptom associated with a positive price shock is a corresponding increase in costs. The best-known reason is that demand for goods and services is intense and there are numerous striking examples across the industry. For example, Transocean announced its first dayrate over $600,000 for its drillship Deepwater Pathfinder for a 4- to 6-month commitment starting in mid-2009.38 With ancillary services such as supply vessels, logging, perforating and drilling fluids the drilling cost will likely exceed $1 million per day. On the downstream end of the business LNG liquefaction costs have increased over fourfold since 2004. Liquefaction costs had been coming down for years prior to the recent increases.39
In testimony before the Alaska Legislature companies argued that finding, development and production costs had ‘more than doubled from 1999 to 2005’. This testimony was provided in an effort to resist oil tax increases. In 2006 costs had risen from $8.00 per barrel of oil equivalent (BOE) to $17.75/BOE.40 However, this argument is not as sound as it may initially appear.
There is another reason why the costs are going up. Higher price expectations make it possible. Fields or field sizes that were once sub-marginal are now feasible. For example, if in the past a development could go forward based on expectations of $20/BBL oil price and full-cycle costs of $8.00/BBL, in today’s world if long-term oil price expectations are say on the order of $50/BBL then, all other things being equal, development could be undertaken with full-cycle costs of around $20/BBL. In each case, costs as a percentage of gross revenues equal 40 per cent. Internal rate of return would be the same.
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5. Today’s changes |
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There is so much fiscal/legislative action during these last few years and it is difficult to keep track of all the changes underway. Some are shrouded in confidential arbitrations and in many countries the changes are multidimensional. Few countries or provinces have settled for a single change and many who have made changes are considering more. For example, Alaska is considering a fourth change to its oil tax in less than 2 years. Some of the more dynamic changes are captured in Fig. 1, which shows activity through 2005. Furthermore, some changes have been ‘self-inflicted’ and some have simply been mechanical as a result of fiscal structure.
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The one common thread is that oil companies, particularly the majors, are struggling to hold on to their position in the face of the overwhelming pressure in almost every country in which they operate. Disputes are underway all over in the court systems and in the form of arbitrations, mediations, conciliations, heavy re-negotiations and public comment periods during legislative sessions and in the court of public opinion.
Unfortunately the backdrop of most of these disputes is unfairly coloured by the perception that oil companies are profiteering. In the court of public opinion, perception trumps reality. And, many governments gain political capital with any increase in dominion over the oil companies.
Changes since 2005 where government take increased include Algeria, Alaska, Angola, China, Trinidad & Tobago and the US Gulf of Mexico. Government take was reduced in Cameroon, Madagascar and Turkey (see Fig. 2).41,42
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6. Milestones |
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Alaska – Democracy under pressure
The Alaska situation provides insight into many of today’s issues and dynamics. Alaska needs a gas pipeline. This will require agreements with unprecedented guarantees and forms of fiscal certainty. The issues of sovereignty and stability are at the heart of this complex mega-project. The pipeline from Alaska’s North Slope to the lower 48 states would transport roughly 4.5 billion cubic feet of gas per day. Proved and probable gas reserves stand at 35 TCF of known gas on the Slope. The construction cost originally estimated at $20 billion a few years ago could end up twice as high with increasing steel prices and labour costs. Assuming average revenues of $6/MCF and full-cycle costs of $2/MCF every single percentage point of ‘take’ represents around $1.2 billion (undiscounted). The situation is pretty intense in Alaska.
In 2005, the producers BP, ExxonMobil and ConocoPhillips, who hold most of the gas, reached a general agreement with Alaska Governor Frank Murkowski. It included terms for the gas pipeline as well as for the oil taxes. It was decided that before the gas terms could be finalized and submitted to the Alaskan legislature, the oil taxes had to be finalized. The producers were demanding ‘fiscal certainty’ for the gas pipeline as well as for the oil taxes – 45 years and 30 years, respectively. However, during the early negotiations the companies would not discuss the issue of progressivity as far as the fiscal design was concerned – the issue was ‘off the table’.
At the beginning of the 2006 legislative session, the Governor presented legislators with the oil tax plan. It was known as the ‘Petroleum Profits Tax’ or PPT 20/20 per cent, which was to replace the old Economic Limit Factor-based severance tax known as ‘ELF’. The ELF tax rate was based on per-well and per-field production levels and was ripe for manipulation.
The Governor’s PPT 20/20 per cent was characterized by a 20 per cent profits-based tax (in addition to state income tax, federal income tax and royalty, etc) plus a 20 per cent direct tax credit for capital expenditures. The credits could reduce the 20 per cent tax rate to an effective tax rate of from 10 per cent to 15 per cent depending on the costs. The Governor’s proposed system came under heavy criticism particularly because it was regressive.43
The Alaskan legislature took the Governor’s proposal and immediately began ‘tweaking’ the terms. Ultimately, in August 2006 the legislature passed the PPT legislation with a 22.5 per cent tax rate and with a progressive element based on oil prices: for every dollar above $40/BBL the tax rate went up by 2.5-tenths of a percentage point.
The proposed gas pipeline agreement was submitted to the legislature in the summer of 2006. These terms were also regressive and as a result the proposal came under even greater criticism particularly because of the producers’ pressure for 45 years of fiscal certainty.
During the legislative sessions in 2006 lobbying efforts were intense both in Alaska’s Capitol, Juneau, and in Washington, DC. The oil industry lobby aggressively appealed to the Alaskan public with full-page advertisements warning of reduced employment and stagnant petroleum investment activity that would result from an increased tax rate. The debate in the legislature and in the media was intense and Governor Murkowski’s popularity plummeted. By the November election he came in a distant third place in the Republican primary election.
Almost simultaneously with passage of the tax bill and defeat of the gas pipeline agreement, agents of the US Federal Bureau of Investigation (FBI) raided the offices of a number of Alaskan state legislators, in Alaska and in Washington, DC, and executives of VECO, the large Alaskan oil service company. Since then seven individuals (three legislators, one lobbyist, two VECO officers and ex Governor Frank Murkowski’s chief of staff) have been convicted of extortion, bribery and/or corruption. It appears there will be more indictments, trials and convictions.
As a result, in 2007 the new Alaskan Governor, Sarah Palin, asked the legislature to re-visit the PPT that she said had been legislated under ‘a dark cloud’. This resulted in a higher tax rate (25 per cent instead of 22.5 per cent) and a more progressive formula: 4-tenths of a percentage point tax increase for every dollar above $30/BBL.
The issue of ‘fiscal certainty' is under debate as the State of Alaska continues with efforts to obtain a gas pipeline.44 One key issue is whether one legislature can legally bind another with the kind of fiscal certainty required for a mega-project like the gas pipeline. Recently, a resolution was filed in the legislature seeking a constitutional amendment authorizing contractual limitation on gas taxes for just such a purpose.45
Within a few months after the passage of Alaska’s latest oil tax in 2007 ENI announced it plans to invest $1.4 billion to develop the Nikaitchuq oil field on the Slope. Sponsors of the oil tax said that this was an evidence that the oil tax had not made Alaska too expensive for companies looking to invest.46
Algeria – Big changes
In 2005, Algeria passed Law 05-07 which repealed law 86-14 (1986 petroleum law). A key element in the 2005 law was the introduction of a new petroleum revenue tax (TRP) which varies from 30 per cent to 70 per cent depending on the accumulated value of production from a field. This was followed by a more widely publicized change which came into effect in July 2006 with the passage of a windfall profits tax (TPE).47
A couple of important aspects of the Algerian changes are (1) Algerian contracts were considered to be some of the more ‘stable’ agreements in the world and (2) the rationale given for the changes. Algeria’s Energy and Mines Minister, Dr. Chakib Khelil stated with respect to the TPE that some companies would not be impacted that much because they already had progressive formulas in their agreements that helped maintain a fair equilibrium between the parties. However, some agreements were not progressive, which meant he said, "that all the super profits were kept by the oil companies. This of course creates a political situation where people will say ‘Well, look what is the state getting out of $60/a barrel. It was getting very good at $15 but at $60 it is getting the same thing. So what is going on?’"48
What he described is shown in Table 1 with an example production sharing agreement that has a 15 per cent royalty and a 60 per cent government share of profit oil. With an increase in the oil price from $20 to $60/BBL government take goes down from 68.6 per cent to 66.6 per cent. This is because there is no corresponding increase in the costs which is somewhat unrealistic. However, it is not so unrealistic for those situations where field development preceded the price increase. The ‘marginal’ government take statistic illustrates how ‘windfall’ profits (the difference between the $20/BBL and the $60/BBL) are divided. Here government take is at its lowest.
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Table 1 illustrates another aspect of today’s high prices – the effect on reserves entitlement with production sharing agreements. With higher prices, IOC entitlement goes down because it takes less cost oil to recover costs when prices are high.
Many governments have found the industry reluctant to go along with price-progressive fiscal systems. One Alaskan argued that many companies believe the future of oil and gas prices is modest compared to today’s prices. So why should they care if a system accommodates the possibility of higher prices?49 The significance of the Algerian changes is that they impact existing contracts and production. Most other changes worldwide govern future agreements and/or licensing.
Bolivia – The disenfranchised
The irony of the Bolivian situation stems from the petroleum sector reforms in 1996, which successfully encouraged exploration and resulted in significant discoveries. The Bolivian reserve base was increased almost ten-fold with proven and probable reserves now estimated at over 50 trillion cubic feet (TCF) of gas.
Rioting in the streets of La Paz in October 2003 claimed from 70 to 100 lives according to various sources and ultimately forced the resignation of the then President Sánchez de Lozada. He had been the president for just over a year. The rioting and unrest were part of ongoing problems.
The name-plate reason for the rioting was the public dissent over the nation’s hydrocarbon policy. President Lozada had proposed legislation providing for export of natural gas to the Pacific Rim LNG markets through Chile (where the liquefaction would take place). Chile is the most direct and efficient place from an economic but not from a political point of view. Chile is the reason why Bolivia is a land-locked country. During the marches and riots in the streets of La Paz were chants of ‘El gas no se vende’ (The gas is not for sale).
Many Bolivians (particularly the indigenous Indian majority) believed that they would not benefit from production and sale of Bolivia’s gas. Bolivian law dictated that royalty income be distributed among the provinces from which the hydrocarbons are produced. Most of the Indians do not live in the hydrocarbon-producing regions. Also, they believe there is not enough gas to justify export – especially to the USA.
The unrest culminated in the 2005 election of Evo Morales who won with over 50 per cent of the popular vote. Morales then scrapped the country’s existing contracts. The New Hydrocarbon Law passed in May 2005 nationalized the oil and gas interests of the country and required the dissolution of any existing joint operating agreements (JOAs) within 180 days. Renegotiation of the JOAs would be drafted under new legislation to include the NOC of Bolivia, ‘Yacimentos Petroliferos Fiscales Bolivianos’ (YPFB). All the production (100 per cent) would be sold through YPFB. The new laws were retroactive, and included a combined tax and royalty rate of 50 per cent (up from 18 per cent) on all the oil and gas production, as well as an additional tax/royalty of 32 per cent for large field production. The new taxes were structured such that most of the increase is distributed to the non-producing provinces.
The problems associated with distribution imbalances are not unique to Bolivia. Nigeria heads the list as far as the intensity of discontent50 is concerned, but it is a huge and growing issue worldwide. Numerous disputes have come through the United States Alien Tort Claims Act of 1789 where foreign citizens can sue US companies in the US court system. Often some of the fundamentals underlying these disputes revolve around the relationship between the plaintiff citizens and their own government – but few citizens are able to sue their own government.
Most of the science of fiscal system analysis and design has focused on how governments benefit from the hydrocarbon production, not how the wealth is distributed. It is not a simple matter and is certainly not highly evolved in many countries.
There are success stories but there are also stories of villagers hiking miles to be at the pay-station where a cousin, employed by an oil or mining company, gets paid. Or where tribal chieftains simply say ‘Give the money to me. I will take care of distribution’.
Increasingly oil companies find themselves on the front lines. Being a good corporate citizen is good no doubt. The virtues of social welfare developments are well known and becoming more common in the petroleum agreements, but nation-building is going a bit far. Whose responsibility is it anyway?
Companies operating in Colombia in the 1990s could enhance their standing in the countryside with various payments and aid, but they had to be careful, some of this activity could be construed as aiding the opposition – an illegal act. It was referred to as ‘vacuna de la gorila’ (gorilla vaccine).
India – Unintended consequences
In 2006, India offered 55 blocks and awarded 52 under its New Exploration Licensing Policy sixth round (NELP VI) licensing. Sixty-six companies responded with 165 bids.51 This was record activity for India. Following the NELP V licensing, in the spirit of added transparency and disclosure, the government expanded the information and guidelines for its NELP VI bid evaluation criteria. As a result and unexpectedly, some of the winning bids were regressive with government share of profit oil starting out high but dropping to as low as 1 per cent or even zero (0 per cent) after company payout.52
There are a couple of lessons here. Many point out that this is an example of oil companies finding a loophole and driving a truck through it. The counterpoint though is, a ‘reasonable’ bid (ie conventional/progressive) would not have succeeded and companies were forced to bid as they did. The other lesson is that the unintended consequences came as the result of a new approach and/or new language – in this case, something as innocuous as the bid evaluation criteria.
Any time governments or oil companies attempt to establish a precedent or address something new in an agreement or system, they should exercise extreme caution. New contract clauses take years to evolve to the point where the ‘wrinkles’ get sorted out. A good example is abandonment/site restoration provisions, which were practically non-existent in PSCs as recently as the mid-1990s. It took years for standards to evolve. The risk of an unintended flaw in an agreement is magnified with stabilizing language.
Britain – A study in volatility
Britain is often cited as a glistening example of fiscal volatility. In the 34 years since the 1973 embargo Britain has imposed, on average, a change every 2 years. In the early 1980s, Britain had some of the toughest terms in the world with a government take in excess of 93 per cent. Just 10 years later, in 1993 it had some of the best terms for exploration licensing with a government take of only 33 per cent (later 30 per cent). Government take now is just over 50 per cent with recent changes in 2002 and 2005. Government take for old legacy fields like Ninian and Forties is 75 per cent.
Despite the volatility, the UK sector of the North Sea has also been quite active over the years – one of the most active offshore provinces in the world.
However, the UK comes under heavy criticism for this volatility. One consultant put it this way: "By that measure (volatility), the worst place to produce oil is not Russia or Venezuela, but Britain which is constantly tinkering with its tax rates".53 Volatility is certainly an issue but for anyone who has worked in Russia or Venezuela this view will seem harsh. Even after all these years following the massive gold-rush-like response to the opening up of the Former Soviet Union, it is hard to find companies who actually made money in Russia the old-fashioned way, ie by finding, developing and producing hydrocarbons at a profit.
The difference between a country like the UK and many others is that Britain makes no pretensions about ‘stability’ and sees no need to design flexibility into the system. For those governments trying to design a flexible system and provide greater stability it is difficult to come up with a design that exhibits that kind of wide-ranging, responsive flexibility that we have seen the UK wield through legislation. While both the UK and the US have also shown an ability to reduce taxes, this contrasts with a trend during the last 10 years where governments have been including in their R factor and rate-of-return-based sliding scale formulas ‘no going back’ language that stipulates once a threshold has been achieved and a higher government take established it cannot go back down.
Another issue that arises with the systems in the UK and the USA in particular is that because neither country provides stabilizing provisions; and American and British oil companies’ demands for greater stability ring hollow to many government officials in other countries.
California – Unpredictable
Perhaps only Americans would be surprised that Californians voted down an initiative to increase oil industry taxes. This was put to a vote in 2006 under a ballot measure known as Proposition 87. It failed with a margin of 54.7–45.3 per cent. The proposition (if passed) would have imposed a severance tax of from 1.5 per cent (at $10/BBL) to 6 per cent (with prices above $60/BBL). Essentially the tax was designed to expire once $4 billion had been raised.54 Overall government take in California (including US Federal taxes and all California taxes and royalties) was already 62 per cent.
Proponents claimed the oil companies out-spent them two-to-one in the public debate with newspaper, radio and television advertisements. This claim may have been true had it not been for one individual who donated $46 million in support of the proposition. California oil industry led by ChevronTexaco, ExxonMobil and Shell financed their defense of the tax increase with $94 million. Their prevailing arguments were that the proposition would (1) dry up oil supplies and (2) increase fuel costs.55
Russia – After the gold rush
Although it is not a happy story, the Sakhalin II project embodies many of the key issues of-the-day in the former Soviet Union (FSU). The Sakhalin II production sharing agreement (PSA) dated 22 June 199456,57 was the first of the 3 Russian PSAs (followed by the Sakhalin I and Kharyaga PSAs). Sakhalin II has been described as ‘an agreement so advantageous it becomes part of corporate lore and is analysed in business school textbooks for years to come’.58 One common explanation is that the government agreed to for go its share of the revenues until the IOCs had recouped their costs.59,60
There is the added claim that the Sakhalin PSA structure transferred ‘most of the risks of both construction overspend and change in the oil/gas price to the Russian government’.61 This claim is fortified with the claim that the government did not foresee the long delays and the increase of projected costs that have afflicted the project.62
Other issues prominent in the Sakhalin II story include claims of environmental abuse and lack of compliance with the Russian 70 per cent ‘local content’ requirement. The key issues and claims associated with the Sakhalin II PSA boil down to the following:
- It is overly advantageous to the IOCs.
- The government must for go share of revenues until the IOC recoups costs.
- Risk of cost over-runs and price volatility shouldered mostly by government.
- Russian 70 per cent local content requirement not being met.63
- Environmental abuses exist at Sakhalin II development.
Arguments 1, 2 and 3 were pillars of YUKOS chairman Mikhail Khodorkovsky’s position when he lobbied against PSA legislation in Russia in the late 1990s. His efforts were based in-part on comparison of PSAs with royalty/tax systems.64
Other claims of lopsidedness in the Sakhalin II PSA are fortified by comparison to a ‘standard’ PSA.65 However, comparing the Sakhalin II PSA with either a standard PSA or with a typical royalty/tax system is misleading. Alternatively, in Table 2 a comparison is made with another large-scale, frontier-type LNG project – Tangguh LNG in Eastern Indonesia.
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Indonesians have considerable experience with both PSAs as well as grassroots LNG project development. Tangguh LNG is the third such project in Indonesia following the Bontang and Arun LNG projects, which came on-stream in 1977 and 1978, respectively. Table 2 below summarises the key aspects and terms of the two projects and the underlying agreements. This comparison of key economic indicators for these two projects indicates that the similarities outweigh the differences on most of the issues outlined above.
There is considerable mention in the industry literature of how the Russian government must for go a share of revenues at Sakhalin II until the IOCs have recouped their costs (plus interest).66 However, during the capital cost recovery phase of this project the Russian government receives a 6 per cent royalty. Under the Eastern Indonesian PSAs (for gas) the government is guaranteed only around 4 per cent of production during the cost recovery period (plus interest).67
The risk of cost over-runs is captured partially with the savings index. Like most petroleum agreements around the world, if the costs increase then there is a reduction in the total available profit oil or gas and/or taxable income. As both the government and the IOC have claim to a share of profits they both stand to suffer to some degree. The savings index measures that. In the Sakhalin and Eastern Indonesian gas agreements, the IOCs have claim to around 34 per cent to 37 per cent of the after-tax profit oil or gas – no real difference. If there is a cost over-run the governments shoulder most of the burden (63–66 per cent) and the companies shoulder the rest. Therefore, this index shows why governments (in both cases) are concerned about keeping costs down. But so are the oil companies. Furthermore, the oil companies’ incentive is magnified when present value discounting is factored-in,68 and this is not shown in Table 2.
The Russian content requirement of 70 per cent is a noble ambition. However, it is hard to imagine that the Eastern Russian provinces have the technology and workforce to adequately supply up to 70 per cent of the goods and services (and 80 per cent of the labour force69) needed for a state-of-the-art, harsh-environment, frontier LNG development. Part of the explanation for IOCs’ lack of compliance with the local content requirement is that the IOCs do not care about keeping costs down, so they have no incentive to use less-expensive local companies.
Claims of environmental abuse are particularly inflammatory these days. For many industry personnel who have worked in the former Soviet Union the claims may seem odd. However, in 2005 the European Bank for Reconstruction and Development (EBRD) said of the Sakhalin II project that it lacked ‘environmental awareness’ and unless the operator improved environmental protection measures funding would be withheld.70
One of the problems with the Sakhalin II agreement unfortunately and probably unexpectedly is self-imposed because of the public statements regarding the virtues of the agreement from the IOC point of view. Steve McVeigh CEO of the Sakhalin Energy Investment Company (SEIC) in 2002 claimed the Sakhalin II PSA had ‘some of the best terms you will ever get in Russia’.71 To many in the petroleum industry this is not saying much but statements like this are being used against SEIC.
The Harvard Business School claimed that Sakhalin II was widely considered to be favourable to SEIC and that the agreement was ‘designed to be attractive to the investors’.72 Frankly, for an industry practitioner this would sound reasonable because Eastern Russia is a particularly harsh frontier environment that required attractive terms to make an LNG project work.
By 2000 the Sakhalin II consortium – SEIC was comprised of Shell (55 per cent), Mitsui (25 per cent) and Mitsubishi (20 per cent). In December 2006 Gazprom acquired a controlling interest in Sakhalin II. It had intended to take a 25 per cent interest plus one share which would have given it veto power. However, just before this acquisition was consummated the Sakhalin partners reportedly changed the charter with respect to passmark voting thresholds without informing Gazprom.73 Whether this story is true or not is not as important as the issue it highlights. Many governments these days are finding that their power and control is or can be mitigated because of the nature and structure of the agreements between consortium members whether it is a charter or a joint operating agreement. Key examples these days include provisions dealing with rights of first refusal, area(s) of mutual interest, sole-risk, unitization and passmark voting rules.
The most cogent complaint about the Sakhalin II PSA is the nature of the rate-of-return (ROR)-based profit oil/gas split and more precisely, the first ROR threshold of 17.5 per cent (real). This means that before the government receives much more than the minimum share of 6 per cent (due to the royalty), the IOCs must receive their money back and a real rate of return of 17.5 per cent.
During the mid- to late 1990s ROR-based fiscal systems began to fall from favour in the industry with claims of potential ‘goldplating’. Even Papua New Guinea, where the approach was first proposed74 has turned away from their ROR-based elements.
While Sakhalin II is the most glaring example of the problems, the Russian government has put considerable pressure on the other large-scale Western oil projects in which the government does not have controlling interest: Sakhalin I; BP’s (BP–TNK) venture, Total’s Kharyaga; and the Caspian Pipeline Consortium (CPC), which exports Kazakh oil through Russia to the Russian Black Sea port of Novorossiysk.
This action in Russia prompted one analyst to state that the future for foreign oil companies in Russia ‘does not bode well’.75 This statement though implies Russia’s past (presumably since the breakup) had some bright moments – although it is hard to find evidence of this.
US outer Continental shelf
Even as various states within the US examine their situation (like California and Alaska) the federal government is also revisiting its position with respect to royalty rate increases as well as another possible windfall profits tax and even (once again) limitations on the foreign tax credit system. One recent study by the Government Accountability Office (GAO) concluded that "the Federal Government Receives among the Lowest Government Takes in the World".76
The GAO report was based on eight published studies of government take around the world. It compared government take in various countries with the US OCS based on federal royalty rates in place prior to 2008. Subsequently, royalty rates have been increased to 18.75 per cent for lease sales scheduled for March 2008 and beyond. Prior to this change, typical royalties were 12.5 per cent for deepwater and 16.67 per cent on the shelf.
Unfortunately, the government take statistic is particularly misleading when it comes to the US GOM.77 This is because of the dominant role of signature bonuses in the US, which are some of the highest in the world in terms of dollars-per-acre. The US government has received over $65 billion in bonuses for the OCS since 1953. Typical government take analysis does not adequately capture the full effect of signature bonuses. The only way to adequately do this is to factor-in present value discounting (as many analysts do with ‘discounted government take’ statistics) and risk (which few analysts do). This notion is not new. One estimate, which factored-in risk and present value, published in the mid-1980s had government take for the US OCS closer to 77 per cent 78 and others found similar results in the late 1990s.79 By contrast typical take statistics for the US OCS are on the order of from 40 per cent to 50 per cent.
The GAO report focused mainly on the government take statistic even though government take is only one of many metrics that quantify and characterize a particular fiscal/contractual structure. Companion statistics provide added dimension. And, the other metrics are important because of the weaknesses of the government take statistic.80,81 Beyond that, whether or not a country’s ‘take’ is adequate or not must also be a function of prospectivity. Unfortunately, this aspect is often lost on legislators and/or the public.
Also, in the US, much of the public is hostile to what they perceive as greedy oil companies. Some of this perception is bolstered by results of a mistake that occurred when US civil servants with the Minerals Management Service (MMS) accidentally left out a critical contract clause in Federal offshore licenses signed in 1998 and 1999. The clause limited the deepwater royalty relief in-place at that time when oil prices exceeded a certain level (roughly $30/BBL). Civil servants admit the language was accidentally omitted and the expected cost to taxpayers could be as much as $14 billion.82 Others place the loss at closer to $60 billion in government revenue.83 Initial efforts to recoup these losses have failed in court. In other words the oil companies are holding the government’s feet to the fire. A federal court ruling in Louisiana supported a position Anadarko had taken that the MMS did not have authority to ‘rectify’ the mistake by trying to collect royalty payments from those leases (where the particular language was missing).84 This may provide short-term benefits to the industry but long-term, the US public (and US congress) can be vindictive.
The US Senate Finance Committee in 2007 defeated a bill that proposed among other things, a 13 per cent excise tax on future Gulf of Mexico production as well as a reduction in the foreign tax credit. The potential result of this bill was an estimated $29 billion reduction in oil company cash flow.85 While the bill was defeated, it may see new life under a new and possibly more liberal US government following elections in November 2008.
One of the key lessons that should not be lost on any government designing or negotiating stabilising provisions in their contracts or systems is that an unforeseen or unintended loophole can be extremely painful.
Libya – Another lesson in leapfrogging
Libya provides another interesting case study. License rounds under the fourth-generation exploration and production sharing agreements (EPSA IV) in 2005 and 2006 were some of the most aggressively attended and competitive the industry has ever seen. Some of the blocks received up to fifteen bids. The bidding has been described by some as a ‘dutch auction’ because effectively the companies bid on how small a share of production they were willing to live with. The resulting ‘self-imposed’ government take for some of the blocks was on the order of 95 per cent.86
The notion of this self-imposition of terms has been magnified recently (in a relatively insidious way) with announcements by the Libyan National Oil Company that it is renegotiating contracts with all of the country’s current oil and gas producers with the aim of tightening fiscal terms to increase the government’s take in line with higher oil prices. The goal is to reshape existing concession agreements and earlier EPSA-2 and EPSA-3 contracts to the EPSA-4 model used in the recent bid rounds. The government like so many others these days wants a larger share.87 The irony is that some of the justification for changing terms is because of the gains obtained through the recent bid rounds. This gets magnified when other governments also use the gains achieved in Libya to justify changes of their own. This happened before in Libya and was known as ‘leapfrogging’.
The approach Libya took with its EPSA-4 licensing was consistent with much of the disclosure and transparency initiatives underway worldwide. Unfortunately, the sealed-bid type of license round with full disclosure does not work so well for countries with modest or questionable geological potential. As a result and as a matter of necessity, non-transparent, negotiated deals will continue to be part of the industry’s future.
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Top1. IOCs-NOCs - Service...2. Historical setting3. Contracts of the...4. Prices and costs5. Today's changes6. Milestones7. Contracts of the...Notes |
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Much of the inspiration for today’s petroleum fiscal systems came from the price shock of the mid-1970s, yet paradoxically few systems were adequately crafted for the price shock of 2003+. At the turn of the century only about 20 per cent of the worlds’ petroleum fiscal systems were truly progressive with respect to oil price.88 Another 5–10 per cent of the regimes were neutral like the UK and Norway, where government take remained about the same regardless of the price. The rest of the systems around the world, roughly 70 per cent were simply regressive and when the oil prices increased, government take went down – usually by at least a couple of percentage points as shown in Table 2. This is what the Algerian Minister Dr. Khelil was talking about.89 For some countries the solution is simple – they simply change the terms as they see fit. But this is frustrating for oil companies and ultimately counterproductive and inefficient.
Understandably, oil companies are pressing for more stable agreements with increased urgency during this frenzy-of-change taking place around the world. With what is happening, who could blame companies for wanting or demanding contract stability? However, the need for stability and progressivity go hand-in-hand.
While everyone appears to have an opinion about the future of oil prices, it does not matter what the oil price forecast is. What matters is that system designs accommodate as wide a range of outcomes as possible. So, even if $200/BBL oil or even $10/BBL oil seems unlikely, systems should be designed to accommodate these possible outcomes.
Progressive systems are considered to be more stable, in fact ‘built-in’ flexibility became a test for regime stability (or otherwise) in a recent comparison of global fiscal regimes by Wood Mackenzie.90
While it appears that international law and modern jurisprudence have validated the use of stabilization clauses,91,92 for many high-risk mega projects of the future they are an economic imperative. Without it Alaska will have no pipeline. However, crafting agreements with the right combination of stability and progressivity is not something that is highly evolved in this industry. This will be a big part of the industry’s future. But it will not be easy. The risk of crafting an unintended loophole is magnified by the specter of accidentally creating something that gets ‘frozen’ for 20 years.
- Definitions
- Government take (%) government receipts from royalties, taxes, bonuses, production or profit sharing and Government participation divided by total cash flow
- Cash flow ($) cumulative gross revenues less cumulative gross costs over life of the project (full cycle). Also referred to as economic profit
- Company take (%) 1 – government take = company net cash flow divided by total cash flow
- Marginal government take (%) government receipts from royalties, taxes, bonuses, production or profit sharing and government participation, divided by total gross revenues. (It is basically a take calculation assuming costs equal zero ie gross revenues equal cash flow)
- Effective royalty rate the minimum share of revenues (or production) the government will receive in any given accounting period from royalties and its (guaranteed) share of profit oil. It does not include government working interest share of production resulting from government participation
- Entitlement the shares of production to which the operating company, the working interest partners and the government or government agencies are authorized to lift. Entitlements are based on royalties, cost recovery, production sharing, working interest percentages, etc. The company lifting entitlement often corresponds to the reserves a company can ‘book’
- Savings index this statistic measures the percentage of any savings that will go to the oil company (or contractor). For example, in the US OCS there is a royalty and a 35 per cent tax rate. If an oil company manages to save a dollar there will be an extra dollar, of taxable income. Thus, any savings are divided between the government (35 per cent) and the oil company (65 per cent). The savings index then would be 65 per cent or 65¢ on-the-dollar. This is almost a direct measure of a company’s incentive to keep costs down. Often when present value discounting is factored-in the incentive is magnified93
- Government take (%) government receipts from royalties, taxes, bonuses, production or profit sharing and Government participation divided by total cash flow
- List of Abbreviations
- BBL barrel
- ELF economic limit factor (as in Alaska oil tax)
- G&G geological and geophysical
- IOC international oil company
- JOA joint operating agreement (same as JVOA)
- JVOA joint venture operating agreement
- M thousands
- MCF thousand cubic feet (gas)
- MBBLS thousands of barrels
- MM millions
- MMBBLS millions of barrels
- NOC national oil company
- PSA production sharing agreement (same as PSC)
- PSC production sharing contract (same as PSA)
- R ratio (as in ‘R factor’)
- R factor ratio of accumulated receipts/accumulated expenditures
- $M thousands of dollars
- $MM millions of dollar
- BBL barrel
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Notes |
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Top1. IOCs-NOCs - Service...2. Historical setting3. Contracts of the...4. Prices and costs5. Today's changes6. Milestones7. Contracts of the...Notes |
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1 Stanley Reed, ‘Why Schlumberger, long a hired gun in oil-field services, is becoming a major force and scaring big oil’ Business Week (3 January 2008).
2 Uchenna Izundu, ‘Khelil says Sonatrach seeking major player status’ (7 January 2008) Oil & Gas J 26.
3 G Phillip, Oil and Politics in Latin America (Cambridge University Press 1982) 84.
4 Production Sharing Contract (Indonesia – Offshore Northwest Java) of 18 August 1966.
5 Production Sharing Contract (Indonesia – Offshore Southeast Sumatra) of 6 September 1968.
6 Juan Carlos Boué and Edgar Jones, A Question of Rigs, of Rules, or of Rigging the Rules? (Oxford University Press, Oxford 2006) 36.
8 Tina Rosenberg, ‘The perils of petrocracy’ New York Times (4 November 2007).
10 ––, ‘Really big oil’ The Economist (10 August 2006) – The report claimed "national oil companies (NOCs) owned or controlled by the governments of oil-rich countries, which manage over 90% of the world’s oil, depending on how you count it".
11 Carola Hoyos, ‘National oil companies: Majors have a tough job’ The Financial Times (29 May 2006).
12 P Roberts, ‘NOC, IOC – Living in perfect harmony?’ Oil, Gas & Energy Law Intelligence (OGEL) (March 2007, August 2007).
15 Jad Mouawad, ‘As profits surge, oil giants find hurdles abroad’ The New York Times (World Business Section, 6 May 2006) – "Paolo Scaroni, the chief executive of ENI, called it ‘the paradox of plenty.’ International Oil companies, he said during a conference in London earlier this year, ‘are awash with enormous cash flows, but their opportunities to reinvest that cash are severely limited’."
16 Carola Hoyos, ‘National oil companies: Majors have a tough job’ The Financial Times (29 May 2006) – "Things would not be so bad for Exxon and its sisters if Latin America's fifth biggest oil producer were the only country favouring national oil companies. But more than 90% of the world's oil reserves are off limits to the likes of Shell, BP and Exxon, a fact that record profits are unable to mask. The signs are writ large on balance sheets from London to Texas. Despite paying out $2 billion a month to shareholders, Exxon has $32 billion in cash and nowhere to spend it, while Shell is struggling to find reserves, managing only a 67% proved reserves replacement rate in 2005".
17 Francisco Parra, Oil Politics – A Modern History of Petroleum (Tauris & Co, Ltd, New York 2005).
19 Indonesian Constitution of 1945 – (art 33 – "All the natural wealth on land and in waters are under the jurisdiction of the State and should be used for the benefit and welfare of the people") (1945).
20 Tengku N Machmud, The Indonesian Production Sharing Contract – An Investor’s Perspective (Kluwer Law International, The Hague 2005) 49.
21 Daniel Yergin, The Prize, the Epic Quest for Oil, Money, and Power (Free Press, New York 1991) 592.
23 David Brown, ‘Brazil heads list of targets – Dark days don’t dim expectations’ AAPG Explorer (August 1999) – "Exploration for oil and gas has become very unattractive in most parts of the world" (Graham Kellas).
24 P Rose, ‘Analysis is a Risky Proposition’ AAPG Explorer (March, 1999) 14 – "All in all, such exploration for new giant fields destroyed value rather than creating it in the 1980s and early 1990s".
25 P Rose, ‘Analysis less risky than intuition’ AAPG Explorer (April 1999) 44 –"Exploration, as a corporate function, lost credibility".
26 C Conn and D White, ‘$400 Billion value destruction over the 1980s’ The McKinsey Quarterly (No 3, Australia 1994).
27 D Johnston, ‘The bidding dilemma – A twenty-year retrospective’ Petrol Account Finan Manag J (Spring 2002).
28 P Rose, ‘Risk analysis and management of petroleum exploration ventures’ American Association of Petroleum Geologists Methods in Exploration Series (No 12, 2001) – "it must be acknowledged that overestimation of prospect reserves is a widespread industry bias that has proved difficult to eliminate".
29 J Alexander and J Lohr, ‘Risk analysis: Lessons learned’ (SPE 49030, Presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibition, New Orleans, 27–30 September 1998).
30 F Harper, ‘BP prediction accuracy in prospect assessment: A 15-year retrospective’ (reprint of AAPG International Conference paper, Birmingham, England 1999).
32 J Boxwell, ‘Top oil groups fail to recoup exploration costs’ Financial Times (10 October 2004) – Wood Mackenzie claimed the top-10 oil groups spent about $8 billion combined on exploration during 2003, but this only led to commercial discoveries with a net present value of slightly less than $4 billion. The previous two years showed similar, though less dramatic, shortfalls.
33 A Latham, ‘Value creation through exploration’ AAPG Explorer (Presentation by WoodMackensie Consultant President, AAPG Annual Meeting, Dallas, TX, July 2004) – "(Top 25 companies) spent $50 billion on exploration but only created $23 billion in value".
34 J Lohrenz and E Dougherty, ‘Bonus bidding and bottom lines: Federal offshore o1il and gas’ (SPE Annual Technical Conference and Exhibition, San Francisco, California, October 1983) – In 1970 after about a decade and a half playing this gambling game, the estimate was that bidders were over $4 billion in ‘deficit’. After about three decades, our estimate is that bidders are about $48 billion behind.
35 J Warren, ‘US OCS operators in the hole by $70–80 billion’ Offshore (Excerpts from 1989 Offshore Technology Conference luncheon speech, June 1989) 26–7.
36 ‘Short-term energy outlook’ Energy Information Administration (regularly published, 8 January 2008) <http://www.eia.doe.gov/steo> accessed 31 January 2008.
38 David Paganie, ‘Near-record lease sale results reflect Gulf of Mexico strength, potential’ Offshore (January 2008) 33.
39 Vivek Chandra, Fundamentals of Natural Gas – An International Perspective (PennWell Books 2006).
40 ConocoPhillips’ Testimony before Alaska Legislature (source: JS Herold, 27 February 2006).
41 ––, ‘Government take study’ Wood Mackenzie (July 2007).
42 Daniel Johnston & Co, Inc data.
43 D Johnston, ‘Alaska’s Proposed Production Tax – PPT 20/20%’ SB 305/HB 488 – Issues for discussion and further research’ (Testimony before House Finance Committee, 6 March 2006).
44 Westey Loy, ‘Conoco stresses need for tax promise on gas pipeline’ Anchorage Daily News (Anchorage, AK 8 January 2008).
46 Stefan Milkowski, ‘Eni Petroleum takes on Alaska project’ Fairbanks Daily News-Miner (31 January 2008).
47 ___, Algeria Hydrocarbon Guide (KPMG Algeria, SPA 1 July 2007) ISBN: 978-9947-87-07-1.
48 ––, ‘A sovereign decision: Algeria, IOCs debate oil law’ Algeria Daily News (Arabesques Press, Routers 2006).
49 Doug Reynolds, Fairbanks Daily News-Miner (25 May 2006) – "Most experts believe the future price of oil and gas is $50 per barrel for oil and $5 per thousand cubic feet for gas. Few expect it to go much higher, and in fact many experts and companies, including ExxonMobil place an extremely low probability of oil and gas prices going much higher. If that is the case, why is there so much resistance to have a progressive tax above those prices?"
50 Jedrzej Georg Frynas, ‘Oil in Nigeria, conflict and litigation between oil companies and village communities’ Die Deutsch Bibliothek – CIP – Einheitswaufnahme (2000).
51 ––, ‘Indian government awards 52 oil and gas blocks under NELP-VI’ (9 February 2007) <http://www.oilgas24.com/bm/Oil/New_Developments/indian-government-awards-52-oil-and-gas-blocks-und.shtml> accessed 6 February 2008.
52 One key bid parameter was an ‘Investment Multiple’ which governed the profit oil split (equal to the contractor’s accumulated pre-tax receipts divided by accumulated capital expenditures – thresholds set at 1.5, 2, 2.5, 3, 3.5+).
53 ––, ‘Barking louder, biting less’ The Economist (8 March 2007).
54 Initiative Constitutional Amendment and Statute (State of California) ‘Proposit