- Nigeria Oil And Gas Concessions Map And License Plate Renewal Fayetteville Nc
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- Natural Gas Concessions
RAS TANURA refinery in Saudi Arabia caught fire Nov. 30, burning for about 2 hr, according to press reports from the Persian Gulf. The fire was believed to have started in the 450,000 b/d refinery's naphtha reformer. Cause was not determined at presstime. POLIMEX-CEKOP LTD., Warsaw, let contract to KTI Group BY, Zoetermeer, Netherlands, to build a 700,000 ton/year crude catalytic reformer unit based on UOP platformer technology to produce unleaded gasoline at Mzrip Plock, Poland. KTI,
An independent initiative to monitor the Oil & Gas industry of Nigeria promoting transparency and accountability in decision making and investment. We would like to show you a description here but the site won’t allow us. Gabon’s 12th shallow and deep-water licensing round is set to close in April and Congo-Brazzaville’s License round phase II in June. Two bigger African producers and fellow OPEC members, Nigeria and Angola, are set to launch landmark and out-of-the-ordinary bidding rounds this year. Africa’s comeback on the global oil and gas map is. The next stage after the verification process is payment for license plate which is done in the bank. The amount required is usually about 50,000 naira. Although this depends on the kind of plate you wish to have. After payment, you will be required to present your receipt and a plate number based on availability will be allocated to you.
Dec 10th, 1990
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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.
1. IOCs–NOCs – Service companies
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.
![Concessions Concessions](/uploads/1/2/6/0/126016372/713037867.jpg)
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
2. Historical setting
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
Nigeria Oil And Gas Concessions Map And License Plate Renewal Fayetteville Nc
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
Nigeria Oil And Gas Concessions Map And License Plate Lookup
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?
3. Contracts of the 1980s–1990s
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.
4. Prices and costs
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.
5. Today’s changes
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.
Frequency of petroleum fiscal changes. Courtesy of Graham Kellas, Wood Mackenzie, from “The terms, they are a changin’ … ”, Industry Research – August 2006.
Frequency of petroleum fiscal changes. Courtesy of Graham Kellas, Wood Mackenzie, from “The terms, they are a changin’ … ”, Industry Research – August 2006.
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
Magnitude of petroleum fiscal changes.
Magnitude of petroleum fiscal changes.
6. Milestones
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.
Changes in government take and lifting entitlement with price increase
Gross revenues $/BBL | |||
−3.00 | −9.00 | −6.00 | 15% Royalty |
17.00 | 51.00 | 34.00 | Net (revenues) |
−6.00 | −6.00 | 0.00 | Cost oil (OPEX + CAPEX) |
11.00 | 45.00 | 34.00 | Profit oil |
−6.60 | −27.00 | 20.40 | Government. share profit oil 60% |
4.40 | 18.00 | 13.60 | Company share profit oil |
31.4% | 33.3% | 34.0% | Company take |
68.6%a | 66.6% | 66.0% | Government take |
52%b | 40% | Company lifting entitlement | |
48% | 60% | Government lifting entitlement |
Gross revenues $/BBL | |||
−3.00 | −9.00 | −6.00 | 15% Royalty |
17.00 | 51.00 | 34.00 | Net (revenues) |
−6.00 | −6.00 | 0.00 | Cost oil (OPEX + CAPEX) |
11.00 | 45.00 | 34.00 | Profit oil |
−6.60 | −27.00 | 20.40 | Government. share profit oil 60% |
4.40 | 18.00 | 13.60 | Company share profit oil |
31.4% | 33.3% | 34.0% | Company take |
68.6%a | 66.6% | 66.0% | Government take |
52%b | 40% | Company lifting entitlement | |
48% | 60% | Government lifting entitlement |
aGovernment cash flow divided by total cash flow: [($3.00 + $6.60)/($20.00 − $6.00) = 68.6%].
bCompany cost oil (in dollars) plus profit oil divided by total price [($6.00 + $4.40)/$20.00].
Changes in government take and lifting entitlement with price increase
Gross revenues $/BBL | |||
−3.00 | −9.00 | −6.00 | 15% Royalty |
17.00 | 51.00 | 34.00 | Net (revenues) |
−6.00 | −6.00 | 0.00 | Cost oil (OPEX + CAPEX) |
11.00 | 45.00 | 34.00 | Profit oil |
−6.60 | −27.00 | 20.40 | Government. share profit oil 60% |
4.40 | 18.00 | 13.60 | Company share profit oil |
31.4% | 33.3% | 34.0% | Company take |
68.6%a | 66.6% | 66.0% | Government take |
52%b | 40% | Company lifting entitlement | |
48% | 60% | Government lifting entitlement |
Gross revenues $/BBL | |||
−3.00 | −9.00 | −6.00 | 15% Royalty |
17.00 | 51.00 | 34.00 | Net (revenues) |
−6.00 | −6.00 | 0.00 | Cost oil (OPEX + CAPEX) |
11.00 | 45.00 | 34.00 | Profit oil |
−6.60 | −27.00 | 20.40 | Government. share profit oil 60% |
4.40 | 18.00 | 13.60 | Company share profit oil |
31.4% | 33.3% | 34.0% | Company take |
68.6%a | 66.6% | 66.0% | Government take |
52%b | 40% | Company lifting entitlement | |
48% | 60% | Government lifting entitlement |
aGovernment cash flow divided by total cash flow: [($3.00 + $6.60)/($20.00 − $6.00) = 68.6%].
bCompany cost oil (in dollars) plus profit oil divided by total price [($6.00 + $4.40)/$20.00].
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.
Comparison of contemporaneous mega LNG projects