By the way, the public expressed worried about the Cambodia’s management of its natural resources revenues that has come under increased scrutiny lately, with environmental and development groups warning its lacks the proper mechanisms to utilize an expected upsurge in revenue.

Son Chhay, Sam Rainsy Party Lawmaker, sent a letter dated on May 7, to Deputy Prime Minister Sok An requesting revealing information about which companies have been awarded the rights to prospect for oil and gas and about the management of revenues from those companies. He also requested revealing information about a US$28 million payment by French Oil Giant Total.

So far, French Oil Giant Total paid US$28 million to Cambodian government by stating that US$20 million was paid as a signing bonus, US$6 million put into a social-development fund and US$2 million was for the administration process.

All oil and gas revenues from payment by companies were paid into the account of the National Bank of Cambodia, which is administered by the Ministry of Economy and Finance, and the Cambodian National Petroleum Authority (CNPA). No any payments will be directed to an individual, such as government official.

Deputy Prime Minister Sok An said in a letter dated June 9 that “like other natural budgets, the money has a single exit and a single entry point with only one commander in chief and one chief of staff. He also added that “no payment has been paid directly to any government official. All payments must be made according to oil agreement and put into an account which is defined by the government.”

Son Chhay was quoted by VOA as saying that “I cannot accept this response; this response does not show transparency in managing payment from companies.” He also added that the use of funds has no transparency, no bank account and no procedures for keeping this fund. “This response means there are irregularities and no transparency.”

Mam Sambath, chairman and executive director of the NGO Cambodians for Resource Revenue Transparency, was quoted by the Post as saying that the premier’s announcement of the Total payment in April was a positive sign for future transparency, but that further disclosure is necessary.

Related posts:

• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• June 3, 2010 — Bilateral trade between Cambodia and Singapore rose 84 percent (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)

Profits boom on strong demand,” read the title of an article on refining in the September 2006 issue of Petroleum Economist. “Time to prepare for the downstream downturn,” read the title of an article on refining that appeared exactly a year later in the same industry journal. “People are beginning to reconsider investments, because they are seeing cost overruns, delays, and quality impairment,” the second article reported [1,2]. The refining industry has been subject to booms and busts, and the titles of these articles encapsulate the swings in the industry cycle.

Challenges facing the refining industry are many. It is not enough that crude oil be refined. The outputs— relative amounts of gasoline, kerosene, diesel, residual fuel oil—must match demand, or else there will be a shortage of some fuels and a surplus of others. The fuel mix of demand is not static but has been changing over time. For example, concerns about rising transportation fuel prices and a desire for higher fuel economy are driving European car owners to turn increasingly to diesel vehicles (which have better fuel economy than gasoline vehicles), increasing demand for diesel at the expense of gasoline and causing an imbalance between demand and supply. The fuels must also meet the specifications set by governments. Fuel specifications are tightening progressively, making refining more costly.

Satisfying the above criteria and remaining commercially competitive requires that the refinery configuration and crude mix be optimized for the market the refinery is serving. This briefing note discusses these and other issues facing the global refining industry today.

Location

The location of a refinery influences its economics, mainly on account of associated transportation costs.

First, refineries serving domestic markets are generally more profitable than those serving the export market. This is because exported fuels are sold at export parity prices: the prices in the destination market minus the cost of shipping. A refinery serving the domestic market in a net importing country, in contrast, may be able to charge import-parity prices, which include freight costs which the domestic refinery is not incurring. This gives a natural advantage to a refinery serving the domestic market over export-oriented refineries. If domestic demand for oil is much less than the capacity of an economic scale refinery—which would be 100,000 barrels per day (bpd) or larger, against oil demand in Cambodia in 2005 of 28,000 bpd [3]—then a refiner is faced with two options: build a small refinery to serve primarily the domestic market, or build an economic scale refinery and export some or even the bulk of the products. A small refinery may not be able to compete with product imports from large, efficiently-run refineries in the neighboring countries. A world-scale export refinery can take advantage of economies of scale, but will face full international competition.

Second, refining domestic crude is generally more economic than refining imported crude. This is because importing crude incurs the cost of shipping crude to the refinery, possibly even a long distance, whereas the cost of transporting domestic crude to a domestic refinery is generally lower.

Third, some locations offer natural protection. A landlocked refinery receiving crude by pipeline might be well-positioned to compete with trucked refined products, but the same refinery located near a large harbor capable of receiving oil products from around the world might struggle to remain competitive.

Declining Demand for Fuel Oil

As suggested in the previous briefing note [4], arguably the most significant reason for the restructuring of the global refining sector is increasingly stringent fuel specifications, and in particular the move for large cuts in the fuel sulfur content. The most commonly adopted fuel specifications are those needed to meet the so-called Euro vehicle emission standards, known as Euro 1, 2, and so on. The sulfur limits on gasoline and diesel corresponding to the Euro standards are shown in Table 1. Developing countries follow similar specifications, but with a time lag. In Asia, the sulfur content of automotive fuels in Thailand is at the Euro 3 level, and in China Euro 2.

The sulfur content of straight-run fuels depends on the crude oil from which the fuels are made. Sulfur levels will be much higher when the crude is sour (containing high sulfur levels; see Note 1 [5] for definitions of sweet and sour). The sulfur content of straight-run fuels increases the “heavier” the fraction (that is, the higher the density): naphtha (feedstock for gasoline) is “lighter” than kerosene, which is lighter than diesel, which in turn is lighter than residual fuel oil, and the sulfur content increases when moving from kerosene to residual fuel oil.

Table 2 compares the sulfur content of straight-run naphtha, kerosene and diesel from two types of crude oil with different sulfur contents: Arabian Medium and Brent. Brent is sweet crude and has a sulfur content of 0.4 percent, while Arabian Medium has a sulfur content of 2.5 percent. As can be seen from Table 2, the sulfur content of straight-run fuels derived from these two crudes differs markedly, and diesel from Arabian Medium contains 250 times as much sulfur as the limit in effect in Europe today.

Table 2 explains why hydro skimming refineries cannot produce products that meet fuel specifications in effect in Asia and elsewhere. A hydro skimming refinery has just enough sulfur-removal capacity to pre-treat the feedstock for its reformer, which makes gasoline. It does not usually have additional capacity to reduce sulfur in heavier fractions, nor does it have a hydrogen production unit to generate additional hydrogen.

Because of the rapidly increasing demand for sweet crudes, the price difference between sweet and sour crudes has widened in recent years, as shown in Figure 1. Global crude oil production is becoming increasingly sour—that is, the sulfur content is rising. This means that those refineries that have invested in processing high-sulfur (cheaper) crudes have benefited from the extra investment made—for hydro treating and hydrogen production—to reduce sulfur.

Declining Demand for Fuel Oil

Another factor affecting the refining industry is the worldwide trend away from burning residual fuel oil, accompanied by solid growth of demand for transportation fuels. Residual fuel oil is being replaced by natural gas (for environmental and efficiency reasons) or coal (for reasons of cost and, in coal-rich countries, local availability) in power plants, and the steep rises in oil prices since early 2004 have added to this fuel switching.

Meanwhile, there are not yet readily suitable substitutes for gasoline and diesel as automotive fuels on a wide scale, this when many countries are reaching the threshold income level above which vehicle ownership increases sharply. The International Energy Agency (IEA) predicts that, globally, transport’s share of oil demand will rise from 47 percent in 2005 to 52 percent in 2030. More than 1 billion additional vehicles will be on the road by 2030, and most of the extra vehicles will be in Asia. As a result, demand for gasoline and diesel will continue to grow steadily [6].

The increasing share of gasoline and diesel in total oil demand has meant that simple refineries without catalytic cracking or hydro cracking facilities are making too much residual fuel oil which they may have to sell at a discount, adversely affecting refinery economics. Table 3 compares the yield of Arabian Medium and Brent crudes. Without facilities to crack residual fuel oil, Arabian Medium yields about 35 percent gasoline (naphtha in the table) and diesel. Compared to global demand for gasoline and diesel of 47 percent in 2005, the yield is not adequate to meet demand. Brent, in contrast, yields 58 percent gasoline and diesel. This also explains why “light” crudes—which contain a larger proportion of (straight-run) naphtha, kerosene, and diesel—are more sought after and fetch higher prices than “heavy” crudes. Typically, light crudes also have lower sulfur content. The combined effect is to widen the price gap between sweet and light versus sour and heavy crudes.

Installing a catalytic cracking or hydro cracking unit would convert residual fuel oil into gasoline and diesel, but these units are expensive and benefit from large economies of scale. As a result, large, complex refineries are increasingly common, meaning that small simple refineries struggle to compete.

Refining Margins

Figure 2 compares the monthly refining margins of five representative refineries in northwest Europe, Singapore, and the U.S. Gulf Coast. Three types of refineries are considered: hydro skimming, catalytic cracking, and hydro cracking. Hydro skimming is the simplest refinery configuration and does not convert residual fuel oil to lighter products. A cracking refinery has a catalytic cracking unit; it may also have alkylation and other processing units that do not involve cracking heavier fractions into lighter fractions. A hydro cracking refinery is similar to a cracking refinery except catalytic cracking is replaced by hydro cracking.

Refining margins in the figure are from the IEA and represent the monetary gain or loss associated with processing specific crude. The margins take into account refinery construction costs, wages and other associated costs incurred in refinery operation, and variable costs of buying and processing crude oil. The refinery margins give an indication of the net return to a refinery, and thus possible investment trends.

In the first two cases, Brent, which is produced in the North Sea in the European continental shelf, is refined in northwest Europe. The next two cases consider refining Dubai crude, produced in the United Arab Emirates, in Singapore. The last case considers a coking refinery on the U.S. Gulf Coast refining Maya crude oil from Mexico. A coking refinery is more complex than a cracking refinery. The average U.S. Gulf Coast refinery configuration has shifted in recent years increasingly to the complex coking refinery, which takes advantage of the growing price gap between heavy sour and light sweet crudes by processing heavy sour crude to produce a high proportional yield of valuable products. Since the early 1990s, Maya crude has been the benchmark heavy sour crude on the U.S. Gulf Coast.

For a given crude oil refined at the same location, hydro skimming refineries consistently have lower profitability than more complex refineries with cracking or hydro cracking capability. The margins for hydro skimming refineries have in fact been mostly negative.

This explains why most new refineries are not hydro skimming. The figure also illustrates high volatility of refining margins. The margin at the representative hydro cracking refinery in Singapore ranges from the high of US$8.26 a barrel to a low of –$0.02. Since January 2004, there have been six months when the refining margin was less than $1 a barrel, and about twice as many months when the margin was less than $2 a barrel, both low margins. In contrast, the coking refinery on the U.S. Gulf Coast is shown to be highly profitable: the refining margin ranged from the high of nearly $30 a barrel to a low of $6.62, averaging $13.12.

That average is higher than the maximum monthly margins of the cracking refineries in northwest Europe and Singapore. The refining margin peaked in September 2005, on account of the shortage of refined products caused by hurricane Katrina. That price spike was transmitted to the rest of the world, as evident from similar, although less pronounced, spikes in Singapore and northwest Europe.

Rising Costs

Rapidly rising demand in emerging economies has resulted in a global shortage of equipment, labor, and materials in recent years, and, as a result, world prices of steel, other materials, engineering design, and engineering labor costs have risen sharply, affecting the petroleum, power, and other industries. A number of refinery projects have been delayed or even canceled.

For example, government-owned Kuwait National Petroleum Company (KNPC) tendered a 615,000 bpd refinery with a budget of US$6.3 billion in 2005. KNPC, however, was forced to withdraw the tender in February 2006 after the lowest bid came in at US$15 billion due to cost escalation. In October 2007, KNPC’s board more than doubled the budget and allocated US$14.6 billion for the refinery [7].

Global Trends

As an illustration of the trend towards larger refineries, the average refinery size in the United States in 1969 was 42,000 bpd. In 1982, the Oil and Gas Journal’s “Worldwide Refining Survey” found 301 refineries in the United States; by January 2008, the number had declined to 131, with an average size of 133,000 bpd. In the intervening years, 170 refineries—more than half of the refineries that existed in 1982—had been shut down and replaced by fewer, much larger refineries through expansion of existing refineries [8].

It is therefore not surprising that new refineries being planned around the world are larger than even the average existing U.S. refinery today. A worldwide survey of new refinery construction, published by the Oil and Gas Journal in April 2007, found 24 refineries under construction or being planned. Of the 24, 21 were larger than 100,000 bpd, and 15 were larger than 200,000 bpd. The minimum size was 70,000 bpd, and the maximum 615,000 bpd. The average size was 260,000 bpd.

Refining is capital intensive with built-in large economies of scale. The industry has not been known historically for high profitability. The poor margins experienced by Asian refineries in 1998–2002 led to the closure of many small and inefficient plants. High margins in recent years have encouraged many new project proposals: as of mid-2007, there were 38 new refinery projects with an average capacity exceeding 260,000 bpd [9].

Some analysts have suggested that there is a risk of over-expansion, especially if the economic growth of emerging markets falters. Rising construction costs in recent years have meant that even oil-rich countries are having difficulties moving forward with new projects.

References

[1] Petroleum Economist. 2006. “Profits boom on strong demand.” September: 8–12.

[2] Petroleum Economist. 2007. “Time to prepare for the downstream downturn.” September: 8-10.

[3] IEA. 2007. “Oil Information: Key World Oil Statistics Volume 2007 release 01.”

[4] World Bank. 2008. “Refining Oil – Part 1.” Petroleum Sector Briefing Note No. 10, April.

[5] World Bank. 2007. “Introduction to Oil and Gas.” Petroleum Sector Briefing Note No. 1. March.

[6] IEA. 2007. World Energy Outlook 2007. Paris.

[7] Oil and Gas Journal. 2007. “KNPC eyes 615,000 bpd Kuwaiti refinery for 2012.” 8 October.

[8] Oil and Gas Journal. Various issues

[9] Petroleum Economist. 2007. “Profits could be trimmed next year.” September: 12–16.

(Source: World Bank’s Special Supplement: Oil & Gas, No. 11, May 2008)

Related posts:

• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• August 10, 2009 — Refining Crude Oil – Part 1 (0)
• August 7, 2009 — Prime Minister called on petrol firms to lower cost (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)

The Petroleum Sector Briefing Notes up to this issue have focused on upstream exploration and production. But crude oil has to be traded, refined, and marketed before it can be used. This note describes what is involved in refining. It outlines the characteristics of various refined petroleum products, followed by a brief summary of main refining processes.

Fuels Produced

Crude oil comprises a large number of compounds, consisting mostly of hydrocarbons (which are made up of carbon and hydrogen), but also such “contaminants” as sulfur, nitrogen, metals, salts, and acids. The lower the levels of these contaminants, the more desirable—and higher priced—the crude is. At its simplest, processing units at refineries take crude oil, separate these various components, convert them through chemical reactions, and produce gas (used internally as a refinery fuel), liquefied petroleum gas (LPG), gasoline, kerosene, diesel, heating oil, and residual fuel oil. These refined products in turn consist of numerous hydrocarbons of varying size and shape. Depending on its configuration, a refinery may also produce lubricants, asphalt, and petroleum coke.

LPG

Also known as bottled or cooking gas when used by households and restaurants for cooking, LPG is a gas at room temperature and atmospheric pressure. LPG is a clean cooking and transportation fuel and behaves similarly to natural gas. Pressurizing it in a container liquefies LPG. It takes much less space to store a given amount of fuel as a liquid than as a gas, and LPG is always sold as a liquid under pressure.

Gasoline

Gasoline is used primarily as an automotive fuel. An important characteristic of gasoline is its octane number, which is a measure of the fuel’s resistance to self ignition (or knocking). A vehicle’s octane requirement is determined by the compression ratio of its engine—the higher the compression ratio, the higher the fuel economy and the higher the octane requirement. There are no benefits to using gasoline with an octane number higher than that which the vehicle engine requires.

If the octane number is lower than required, however, the resulting knock can damage the engine. Modern gasoline engines require a research octane number (octane number that is applicable in city, as opposed to highway, driving conditions) of 91–92 or higher, depending on the engine’s compression ratio.

For environmental and health reasons, other characteristics that are increasingly regulated around the world include gasoline’s volatility (temperature stability) and amount of sulfur, metals, and aromatics (a type of hydrocarbon, one of which is benzene). If gasoline is too volatile, it may cause vapor locks during driving (resulting in a temporary loss of power or even stalling) as well as excessive evaporation of light hydrocarbons.

Light hydrocarbons can contribute to ground-level ozone air pollution, and for this reason tight volatility limits are imposed in cities with ozone problems. High ambient concentrations of ozone can cause respiratory illnesses and even premature mortality.

Growing environmental health concerns in recent years have called for lower levels of sulfur, metals, and aromatics. Sulfur interferes with the operation of catalytic converters—by far the most effective means of reducing pollution from gasoline vehicles. The United States, Europe, and Japan are now mandating the so-called sulfur-free gasoline and diesel. It is not possible to rid gasoline (or diesel) of sulfur completely, but the automotive fuels in these areas have the vast majority of sulfur removed during refining, at great expense. In addition to interfering with the operation of catalytic converters, high sulfur levels in gasoline (and diesel) can contribute to acid rain and fine particulate formation in the atmosphere. Fine particulate air pollution is the most serious threat to public health from urban air pollution in most developing country cities.

Environmental health concerns have also led to fuel standards requiring no measurable amounts of heavy metals, the most famous of which is lead. Historically, lead has been added to gasoline as an octane enhancer. But mounting evidence of the damaging public health impact of lead, and particularly on the intellectual development of children, has resulted in a worldwide call for a ban on the use of lead in gasoline. Gasoline in most countries is lead-free today.

Lastly, aromatics enhance gasoline’s octane number but are associated with two environmental health problems. One is that some aromatics break down inside engines during combustion and are emitted as benzene, a cancer-causing agent. Benzene in gasoline may also be emitted out of the tailpipe unburned. Another is that larger-size aromatics can lead to ozone air pollution. Before these problems became widely known, aromatics were used extensively without limits as an octane enhancer, especially after gasoline lead phase-out began. Today, alternative sources of high-octane gasoline components are sought.

Kerosene, diesel, and heating oil

These fuels are collectively known as middle distillates; diesel and heating oil are also known as gasoil. Kerosene is used as an aviation fuel as well as for cooking, heating and lighting. The fuel specifications for kerosene are not as severe as those on gasoline and diesel.

Diesel is used first and foremost as an automotive fuel, and also for power generation. Specifications for automotive diesel are increasingly tightening. The equivalent of the octane number for diesel fuel is cetane: automotive diesel fuel must meet a minimum requirement for the cetane number. The same drive to minimize sulfur in gasoline is also leading to fuel specifications that call for sulfur-free diesel. Ultra low-sulfur diesel enables adoption of advanced exhaust emissions control devices to control the emissions of fine particles and oxides of nitrogen (NOx).

Fine particulate emissions from diesel engines are among the most damaging pollutants and have been receiving considerable attention from policymakers, environmentalists, and health specialists. NOx is responsible for acid rain, ground-level ozone, and fine particulate formation in the atmosphere. Advanced exhaust emission control devices can make diesel vehicles virtually as clean as advanced gasoline and even natural gas vehicles.

Heating oil is similar to diesel fuel and is burned in furnaces in buildings. Kerosene, diesel, and heating oil can be used interchangeably to a considerable extent without the user noticing marked differences, at least in the short run. Illegal adulteration of diesel—which must meet the most stringent fuel specifications—with kerosene or heating oil occurs in many developing countries.

Residual fuel oil

Residual fuel oil is what is left over after other fuels are produced. It is used to power ships’ engines, for generating electricity at power plants, and as a fuel for industrial boilers. Two important characteristics of residual fuel oil are its viscosity and sulfur content. Viscosity can be thought of as the ease with which a fluid flows—water is much less viscose than residual fuel oil. As with gasoline and diesel, the sulfur specifications for residual fuel oil are increasingly being tightened.

Refinery Processing Units

There is wide range of refineries, from simple topping refineries to very large, complex refineries integrated with petrochemicals plants. The tighter the fuel specifications that a refinery must meet, the larger, more complex and expensive the refinery is likely to be. A simplified diagram of a refinery is sketched below.

Crude distillation Units

Every refinery has one or more crude distillation units and the entire crude is fed to these units first, where it is heated. Distillation separates the various components of crude oil according to their boiling points. The temperatures at which compounds boil are affected by pressure. Atmospheric crude distillation units, which every refinery has, operate at normal pressure. Some refineries have vacuum distillation units, which operate below atmospheric pressure to separate residual fuel oil further into different components.

The nameplate capacity of a refinery is the combined capacity of its atmospheric crude distillation units. Refineries that have only atmospheric distillation units are called topping refineries. Fuels made from distillation and with no further chemical reaction are called straight-run fuels. Absent tight fuel specifications, virtually all straight-run fuels can be used without further modification, except gasoline. The octane number of straight-run gasoline is normally too low and further upgrading is required.

Topping refineries are usually small and common in remote areas. Straight-run diesel and a few other fuels may be consumed locally, and the rest may be put into a pipeline to be sent to more sophisticated refineries.

Reforming units

Reformers increase the octane number of naphtha (and more specifically what is called heavy naphtha). Naphtha is a portion of distilled crude oil comprising components with the same boiling points as those making up gasoline. Reforming units increase octane by converting hydrocarbons to aromatics. This is needed up to a point, but recently environmental health concerns have led to limits on relying solely on aromatics for boosting octane.

Reformers are also an important source of hydrogen, which is needed for removing sulfur compounds. Reformers use catalysts (catalysts speed up chemical reactions) that are readily poisoned by sulfur, and therefore the feedstock to a reforming unit is treated first to reduce sulfur to a negligible level in a unit called a hydrotreater. All hydrotreaters consume hydrogen, typically sourced from the reformer.

Refineries with only distillation, reforming, and associated hydro treating units are called hydro skimming refineries. They represent the simplest refinery configuration among refineries that produce usable refined products.

Isomerization units

Isomerization units take what is called light naphtha and, by means of a chemical reaction, increase its octane. There is no environmental health damage associated with the products of isomerization units. Isomerization units require a hydrotreated feedstock.

Catalytic Cracking units

Catalytic cracking units take heavier fractions of dis tilled crude oil and, using a catalyst, break them up into smaller components to make gasoline and middle distillates. Catalytic cracking products have a high sulfur content unless the feedstock has been pretreated to remove sulfur—which is an expensive process. Catalytic cracking produces high-octane gasoline components but poor quality diesel. The sulfur in the cracked products can be lowered by reacting with hydrogen, but doing so typically lowers the octane number of the gasoline fraction. Catalytic cracking is an important source of a feedstock component for alkylation (see below).

Hydrocracking units

In hydrocracking, heavier components of distilled crude oil are cracked in the presence of hydrogen to produce high-quality middle distillates. Hydro cracking units require large amounts of hydrogen and are expensive.

Alkylation units

Alkylates are premium gasoline blending components: they have exceptionally high octane numbers, and, unlike aromatics, are relatively safe for public health. However, alkylation units require other processing units to produce the feedstock: catalytic cracking and (possibly) isomerization units. Alkylation units require hydrotreated feedstocks.

Hydrogen units

The drive to reduce sulfur in fuels is leading to a hydrogen imbalance in refineries. Hydro cracking and hydro treating require hydrogen, with hydro cracking requiring far more than hydro treating. The only source of hydrogen as a by-product of refining processes is reforming. The amount of hydrogen produced during reforming increases with increasing amounts of aromatics made, but with the new interest in limiting the aromatics content in gasoline, the amount of hydrogen produced by reforming units has been declining in recent years. To meet the demand for hydrogen, refineries are building dedicated hydrogen units, where hydrogen is made from methane. This adds to the cost of refining processes.

Economies of Scale

It is not possible to meet tight fuel specifications without hydro treating and other processes, all of which benefit from large economies of scale. A standard rule of thumb used in the industry is that the cost per unit size increases with increasing overall size of the processing unit with a power of 0.6. For example, if a 15,000 bpd unit costs US$150 million to construct, building the same processing unit twice the size—30,000 bpd—will not double the cost to US$300 million but will increase it to US$227 million (=150´20.6). That is, a 15,000 bpd unit costs US$10,000 per daily barrel (US$150 million divided by 15,000 bpd), but a 30,000 bpd unit costs US$7,579 per daily barrel. This scaling factor makes it cheaper to make refined products in large refineries. These economics are driving oil companies to build fewer and larger refineries.

Refining does not generate much employment. Valero, the largest refiner in the United States with 15 refineries, employs on average about 510 workers at each refinery which has an average size of 200,000 bpd. The number of employees at Valero increases with refinery capacity with a power of 0.89. The number ranges from 220 workers at an 88,000 bpd refinery to 820 at a 340,000 bpd refinery [1].

Observations

Refining is an important part of the petroleum supply chain and its economic structure is different from that in the upstream. The ease of refining a particular crude plays a role in determining the refinery economics, and the types of products that are increasingly in demand require more complex processing.

Small hydroskimming refineries continue to operate, usually under protection, in a number of developing countries. They are finding it increasingly difficult to meet modern fuel specifications, yet governments are often reluctant to take the politically difficult step of opening up the market to competition for fear that such a step might lead to eventual closure of the refinery. The next briefing note will deal with market trends in refining.

References

[1] Valero Energy Corporation at www.valero.com/.

(Source: The World Bank Newsletter, Petroleum Sector Briefing Note, no 10, April 2008)

Related posts:

• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• June 19, 2009 — Oil Revenue Not Likely Until 2013 (0)
• June 15, 2009 — Vietnam’s petroleum company met Sok An (0)
• August 7, 2009 — Prime Minister called on petrol firms to lower cost (0)
• June 11, 2009 — Contracts for Petroleum Development – Part 1 (1)
• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)

The Premier said that the two firms that help contribute to reduce gasoline price are Sokimex and Tela companies.

According to the figure from the ministry of commerce on Wednesday, Tela and Caltex sell their oil at the same price – both gold brand and silver brand.

The Cambodian government regularly holds meetings with petroleum companies operating in the Kingdom in which both sides regularly discuss pricing and ways to reduce costs for the consumers as well as methods for addressing Cambodia’s dilapidated public transport system, reported the Phnom Penh Post.

Related posts:

• August 10, 2009 — Refining Crude Oil – Part 1 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• June 15, 2009 — Vietnam’s petroleum company met Sok An (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• June 19, 2009 — Oil Revenue Not Likely Until 2013 (0)
• June 11, 2009 — Contracts for Petroleum Development – Part 1 (1)
• June 1, 2009 — Country Experience with EITI – Part 2 (0)

Briefing Notes 7 and 8 [1,2] gave an overview of different types of contractual arrangements in the upstream petroleum sector and defined key payment streams under production sharing agreements (PSAs). This note, the last in a three-part series, provides quantitative examples of how varying fiscal parameters affect the size and timing of government revenue streams. To this end, the note takes two sets of fiscal parameters—one progressive and the other regressive—and follows revenue streams over the life of a contract.

Two Fiscal Systems

The simulations take a hypothetical field that, over 19 years, produces 100 million barrels of oil. The production profile (Figure 1), associated costs, and financial flow calculation methodologies are taken from [3]. The simulation considers both steady oil price levels and the historical annual price of Brent crude oil—an important marker crude whose price movement is taken as a barometer of the overall oil market—expressed in 2006 U.S. dollars[1] between 1988 and 2006 (Figure 2). The average price in Figure 2 is $30 a barrel. The first year of operation is the year in which the contract becomes effective. It is worth noting that the start of production in Figure 1 is much sooner than what occurs in practice; the exploration period was shortened for brevity in this note.

The two fiscal cases are summarized in Table 1. In both cases, for income tax purposes, straight-line depreciation of capital expenditures over five years is assumed and there is no limit on the recognition of expenses incurred for petroleum operations, which may be carried forward from one year to the next until they are fully recovered. For computing the government’s share of profit oil in production sharing, a ceiling on cost recovery is imposed in one case. Smaller payments, such as surface rental and other fees, are omitted for simplicity.

The first case considered is regressive: royalty, tax, and production sharing rates do not increase with increasing net-of-cost income. There is a signature bonus of US$20 million, the royalty rate is fixed at 10 percent, and cost recovery for production sharing is restricted to 60 percent in any given accounting period. All these provisions are designed to ensure early revenue. The government receives 70 percent of profit oil. After these payments, the contractor pays an income tax of 30 percent on profits derived from the remaining income.

The second case does not have a signature bonus and has sliding scale royalty and production sharing schedules, the details of which are shown in Table 2. The royalty rate does not reach 10 percent, the rate set in case 1, until the extracted oil fetches at least US$25 a barrel. As the oil price increases, however, the royalty rate rises with it and reaches a maximum of 40 percent above US$60 a barrel, considerably above that in case 1. The government’s share of profit oil increases as the contractor’s internal rate of return (IRR) increases. As Briefing Note 8 described, this sliding scale production share makes this PSA a rate-of-return contract. The government share is zero if IRR is 20 percent (in practice, and especially in new PSAs, the government shares production from the outset), and is only 40 percent when IRR is between 20 and 30 percent. The government’s share rises rapidly above this threshold, and is as high as 90 percent when IRR exceeds 50 percent. In case 2, an income tax of 30 percent is paid before profit oil is shared.

Impact of Different Price Levels

Constant oil price scenarios

Calculations were carried out assuming different constant oil price levels. In each scenario, a constant oil price was assumed during the entire life of the contract, and the same calculation was repeated at seven price levels, ranging from US$20 to $80 a barrel.

Figure 3 shows the percentage of net-of-cost income that flows to the government. Each price level represents a scenario run. Annual revenues were computed using discounted cash flow analysis to take the time value of money into account (see Briefing Note No. 7). The discount rate used in this note was 12.5 percent. The percent received by the government was computed by dividing the aggregate discounted government revenues by total discounted receipts from the sale of oil minus total discounted expenditures (that is, net income).

It is immediately clear from Figure 3 that the two fiscal systems are very different. In case 1, the percent received by the government declines with rising oil price, whereas the reverse is observed in case 2, clearly illustrating that case 1 is regressive, case 2 progressive.

Figure 4 shows the contractor’s rate of return, which is a measure of profitability. In case 1, the rate of return is markedly lower than that in case 2 at low oil prices, but the two curves cross near US$45 a barrel above which case 1 gives higher rates of return. That is, case 1 is unattractive to investors in a low oil-price environment but very attractive if oil prices soar.

What these two figures illustrate is that a progressive regime is more likely to assure a reasonable return to investors even when world oil prices are low (or alternatively in high-cost fields, such as marginal fields), but limits the amount of profits that the contractor can earn in “good times.” Conversely for the government, a progressive regime may provide less revenue when times are tough—low oil prices, high production costs, or both—but provide more income if the project becomes profitable.

Impact on Revenue Flow

Figure 5 shows annual government revenues using the oil price history shown in Figure 2. This assumes that the price of oil extracted in this hypothetical field fetches the same price as Brent. There are marked differences between the two cases during the first five years. In the first year, the government receives a signature bonus of US$20 million in case 1 but nothing in case 2. The government receives no revenue in year 2, and in practice years of little revenue will last longer than a year. As production starts, government revenue rises more rapidly in case 1, but falls below that in case 2 beginning in year 7. Government revenues in case 1 are more front-loaded.

Table 3 compares the overall government revenue over the life of this oil field at different (constant) oil price levels, calculated using discounted cash flow analysis. In case 2, despite being back-loaded, the aggregate revenue is lower than in case 1 below US$40 a barrel, but is 14 percent higher at US$80 a barrel, a highly profitable scenario, The ratio of government revenues is higher for a doubling and quadrupling of oil prices in case 2.

Observations

The two cases discussed in this note illustrate the type of trade-offs that governments have to consider in setting fiscal parameters. So-called regressive parameters are more likely to ensure early revenue as well as minimal revenues in adverse circumstances, but also to discourage investments, especially in marginal fields. Progressive regimes may encourage investments in adverse situations and also increase government revenues in favorable circumstances, but could delay the arrival of government revenues and reduce them if oil prices fall, production costs increase, or both.

Table 3 also illustrates that, as one would expect, the impact of oil price variation on government revenue volatility is amplified if fiscal parameters are linked to profitability indices. But it is difficult to try to control revenue volatility by means of fiscal parameters. A recommended approach is to design the fiscal system to maximize government revenue in the long run, and to use other instruments¾such as oil funds or risk management strategies including hedging¾to deal with revenue volatility.

In all cases, the government’s (and the government’s perception of investors’) assessment of future oil price movements, production cost escalation, and the field’s prospectively (its attractiveness as an exploration target) will influence how to set fiscal parameters for long term government revenue maximization.

This three-part series has had to simplify complex issues for the sake of readability and brevity. The long term nature, large upfront investments, and significant uncertainties surrounding petroleum projects present a considerable challenge to the formulation of the fiscal framework and contractual terms in any country. It is important to note that, because each project is situation- specific, fiscal systems cannot merely be transplanted from one country, area, or project to another; what works well in Algeria may not work well in Cambodia. In this regard, it is important to retain flexibility in fiscal systems¾capable of adapting to changes in market conditions, government policy, and geological and country risks.

References

[1] World Bank. 2007. “Contracts for Petroleum Development – Part 1.” Petroleum Sector Briefing Note No. 7, October.

[2] World Bank. 2007. “Contracts for Petroleum Development – Part 2.” Petroleum Sector Briefing Note No. 7, November.

[3] Daniel Johnston. 2003. International Exploration Economics, Risk, and Contract Analysis. Tulsa, Oklahoma: PennWell Corporation.

(Source: World Bank Newsletter, Petroleum Sector Briefing Note, February 2008)

Related posts:

• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• June 15, 2009 — Vietnam’s petroleum company met Sok An (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)

Many developing countries around the world use production sharing agreements (PSAs) to govern the relationship between the state and petroleum companies. PSAs in the oil sector were first developed in Indonesia; the Asian governments that have used production sharing include China, India, Malaysia, Pakistan, the Philippines, Timor Leste, and Vietnam. Beginning in 2002, the government of Cambodia has signed a series of PSAs.

Briefing Note No. 7 gave an overview of the legal framework governing the petroleum sector and two types of contractual systems, concessionary and production sharing [1]. This note discusses in more detail different aspects of fiscal terms in production sharing.

There is a fundamental conflict between petroleum companies, referred to as contractors in production sharing, and the government: both want to maximize their respective revenues and minimize risks. The government can potentially increase its revenue by setting tax, royalty, and other rates at high levels, but doing so could deter investment, especially in marginal fields, and reduce, rather than enhance, the government’s overall revenue. Judging what would be a reasonable burden on petroleum companies is one of the challenges in setting up an effective fiscal system.

Responding to Market Incentives

Briefing Note No. 7 explained that some fiscal terms are regressive and others are progressive.

Briefly, if the percentage of the net-of-cost income flowing to the government increases with increasing income¾that is, government income rises at a faster rate than the net-of-cost project income¾the fiscal parameter is progressive. Progressive parameters tend to be based on some measure of profitability. To reflect profit elements, two approaches are often used.

• An R-factor is the ratio of cumulative receipts from the sale of petroleum to cumulative expenditures. This ratio is initially zero¾during exploration there is no sale of petroleum while there may be considerable expenses¾and gradually grows in time. An R-factor less than 1 would mean that costs have not been fully recovered yet: total expenditures exceed total receipts. The larger the R-factor, the more profitable the operation. The royalty rate or the government’s share of production may increase with increasing R-factor.

• In the rate-of-return contracts (also referred to as resource rent royalties, resource rent taxes, or trigger taxes), the government receives additional income from the contractor’s cash flows in excess of specified thresholds for the internal rate of return. The rate (for royalty, tax, production share) due to the government increases with increasing rate of return¾the more profitable the operation, the higher the rate.

Fiscal parameters based on either of these are among the most progressive.

Revenue Streams

Typical revenue streams in a PSA are shown in Figure 1. Oil (or gas) produced is split into cost oil, profit oil, and the royalty.

Royalty

Royalties are based on the volume or value of petroleum extracted. Royalties may be paid in cash or in kind; if the latter, specified amounts of oil, gas, or both are delivered to the government. Royalties are paid as soon as commercial production commences, thereby providing early revenue to the government.

They also ensure that contractors make a minimal payment. Simple royalties¾for example, 10 percent of the value of the oil extracted ¾ are easy to administer, but do not take into account the profitability of the project and hence are regressive. As such, royalties deter investment. One way of redressing this is to make the royalty rate depend on the level of production, increasing it with increasing production.

The rationale is that larger production levels lead to greater profitability because of economies of scale (this is not always the case, because many factors other than the scale of production affect a project’s profitability). In that case, royalties are said to be on a sliding scale. Some countries have designed the royalty rate to depend on the R-factor.

Cost oil

Cost oil refers to the oil retained by the contractor to recover the costs of exploration, development, and production. Most PSAs limit the amount of cost oil that can be retained in a given accounting period. Costs that are not recovered are carried forward and recovered later; most PSAs allow virtually unlimited carry forward. The cost oil limit is the only substantive distinction between concessionary systems and production sharing. It is another avenue available to the government to ensure early revenue.

Certain expenses may not be eligible for cost recovery. Examples include bonuses (see below), royalties; interest or other financing related payments and overheads beyond specified limits; and costs outside the budget, unless approved by the government.

Profit oil

Profit oil is the share of production remaining after the royalty is paid and cost oil has been retained by the contractor. Profit oil can be paid in cash or in kind. In its simplest formulation, the agreement may stipulate that the profit oil be split, for example, 40/ 60¾the contractor’s share being 40 percent and the government’s share 60 percent¾irrespective of the world oil price or production level. Production sharing can also be on a sliding scale: the percent share of the government can increase with increasing production level, cumulative production, R-factor, or rate of return.

Income tax

In Figure 1, the contractor is subject to income tax based on taxable income. Income tax is paid after production is shared in this figure; it is also possible to write a PSA in which income tax is paid before production sharing (see Briefing Note No. 9). A PSA does not have to provide for the actual payment of taxes, and instead can include the tax equivalent portion in the government’s share. Known as a pay-on-behalf scheme, it assures stability with respect to income tax. The tax equivalent portion is subtracted before production sharing.

Bonuse

Bonuses are the most regressive fiscal parameters and give early revenue to the government. Signature bonuses are paid when the contract becomes effective, and can be considerable in highly prospective areas. For example, the first financial report for the Nigeria Extractive Industries Transparency Initiative showed that Shell Nigeria Ultra Deep Limited in 2003 paid US$210 million as a signature bonus [2]. In 2006, a new record was set when Sonangol-Sinopec International, a joint venture between two national oil companies from Angola and China, bid a total of US$2.4 billion for the relinquished parts of two blocks in Angola [3]. Production bonuses are paid at the start of commercial production and when production reaches specified levels. Bonuses are generally not recognized as cost-recoverable expenses.

Surface rental and other fees

Contractors pay annually for acreage covered by a PSA. Surface rental fees are often given in monetary units per square kilometer, so that the overall flow to the government declines with each relinquishment. There are other fees, such as fees paid by bidders in licensing rounds or contributions to the training of government personnel which, if not spent, are payable in cash.

Other taxes

Other taxes include withholding tax, foreign national and sub-contractor income tax, value added tax, and customs duties.

Payments in kind

Contractors may undertake social programs (such as building schools and clinics) and infrastructure development (such as building roads) on a voluntary basis. Training of local employees is another example. Training of government officials is normally a contractual obligation.

Accounting Rules

Accounting rules also affect how much and when the government will receive revenues from contractors. It is not the intention of this note to explain these rules, but they are mentioned to give a sense of what contractors look for. They include ring-fencing by contract (or sometimes by field), depreciation rates, allowance for accelerated depreciation, loss carry forward, treatment of pre-production expenses, uplifting of costs, rules against thin capitalization, and treatment of abandonment costs.

Foreign Tax Credit Considerations

Foreign petroleum companies must pay income tax to their home governments. Foreign companies are allowed to credit taxes paid to the host government (the government of the country in which petroleum operations are being conducted) against tax liabilities in their home countries, provided that the tax in question is an income/profit tax and a tax certificate is issued by the host government[1]. In pay-on-behalf schemes, to enable foreign tax credits, the host country taxes are still calculated and the host government issues a tax certificate.

Everything else being equal, it does not make sense to set the income tax rate markedly lower than those prevailing in the countries where contractors are headquartered, because that would likely mean that the difference would be paid to foreign tax authorities -the host government would be sacrificing tax revenue to foreign governments when doing so offers no additional incentives for investment.

How Payments Are Made

Signature bonuses, as explained above, are paid before any work starts. Surface rental fees and a few other fees and taxes are paid prior to production, but they are relatively small. Once commercial production starts, Figure 1 gives an illustration of what happens to receipts from petroleum sale. The royalty is paid first. The contractor is next allowed to recover costs, often up to a specified limit, in the form of cost oil. Revenues remaining after royalty and cost recovery constitute profit oil (or gas), and are shared between the government and the contractor. In Figure 1, the contractor is further required to pay income tax on its share of profit oil.

While bonuses and royalties start flowing early on, corporate taxes and the government’s share of production usually do not start flowing in significant amounts until costs are substantially recovered. Because upfront investment costs in oil and gas may be very large, it could take several years from the start of production before the government receives any sizable revenue.

Illustration

A very simplified case is given in Figure 2 to illustrate how the system in Figure 1 may work. For simplicity, only the royalty, production share, and income tax are considered; bonuses, depreciation and loss carry forward rules, surface rental and other fees, and other taxes and payments due are not considered.

Figure 2 considers the proceeds from the sale of two barrels of oil at US$50 each, giving a total of $100 in gross revenue to be shared between the contractor and the government. In accordance with Figure 1, the royalty is paid first. At 10 percent, this amounts to $10 going to the government. Out of the remaining $90, the contractor recovers costs to the limit permitted, in this case 60 percent of the gross revenue or US$60. The total expenses incurred (including pre-production expenses) amount to US$25 for these two barrels, and the contractor can take as cost oil the full cash expenditures incurred because US$25 is less than the maximum allowable limit of US$60.

This leaves profit oil of US$65. The production split in the PSA is 40 percent for the contractor and 60 percent for the government. The government takes 60 percent of US$65, or US$39, and the remaining US$26 goes to the contractor. The contractor has to pay income tax out of its share of profit oil. For paying income tax, there are no limits on deductible expenses in the way there are limits on cost oil. (In this example, however, costs recovered in this accounting period happen to be the same for both cost oil and for income tax purposes.) The taxable income is

US$26 (100–10–25–39), giving an income tax of US$7.8. The end result is that the contractor retains US$43 and the government takes $57.

In practice, calculations of revenue streams are more complex because of depreciation, loss carry forward, and the determination of deductible costs (for tax purposes) which normally differ from recoverable costs (for computing cost oil). The next briefing note will illustrate how different fiscal terms can affect revenue flows to the government over the life of a contract.

References

[1] World Bank. 2007. “Contracts for Petroleum Development – Part 1.” Petroleum Sector Briefing Note No. 7, October.

[2] Hart Group. 2006. “Nigeria Extractive Industry Transparency Initiative Financial Audit. Financial Flows 1999”2004.” www.neiti.org/files-pdf/FARFinFlowsUpload.pdf.

[3] Global Insight Daily Analysis. 2006. “Angola set for new licensing round, Gimboa field developments.” August 31.

(Source: World Bank Newsletter, Petroleum Sector Briefing Note, November 2007)

Related posts:

• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• August 10, 2009 — Refining Crude Oil – Part 1 (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• August 7, 2009 — Prime Minister called on petrol firms to lower cost (0)
• June 19, 2009 — Oil Revenue Not Likely Until 2013 (0)

According to the hand-written statement by the council, Dinh La Thang, president of Vietnam Oil company, led a delegation that met Sok An to express the company’s interest in searching for oil in Cambodia, reported The Cambodia Daily.

“Excellency Sok An welcomed the intentions of Vietnam Oil and urge the company to continue to cooperate and hold further discussion with the Cambodian National Petroleum Authority.

Discussion at the hour-long meeting had not been very detailed and did not include the designation of areas for oil exploration, adding that the company had just asked for initial support from Sok An, On Chandar, Information Officer for Council of Ministers, quoted by the Cambodia Daily as saying.

Related posts:

• August 10, 2009 — Refining Crude Oil – Part 1 (0)
• June 19, 2009 — Oil Revenue Not Likely Until 2013 (0)
• June 11, 2009 — Contracts for Petroleum Development – Part 1 (1)
• March 30, 2009 — Introduction to Oil and Gas (0)
• August 7, 2009 — Prime Minister called on petrol firms to lower cost (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)

“This ‘curious coalition’ that we hear about has been remarkably effective in demonstrating what you can achieve through a voluntary and consensus-building process in which governments, civil society, the companies and many others have all felt inspired to play a leading part,” so began the remarks by Richard Paniguin of BP at the EITI plenary conference in London in March 2005 [1–3]. He went on to cite the experience of Azerbaijan, which had pledged to become a pilot country in implementing EITI in 2003.

The government of Azerbaijan’s “strong commitment was based on the understanding that EITI objectives substantially correspond to the government’s development agenda,” stated Samir Sharifov, Executive Director of the State Oil Fund of Azerbaijan, at the same conference. Pointing to support at the highest political level as being essential to effective implementation of EITI, Samir Sharifov highlighted the important role that the November 2004 memorandum of understanding signed by various stakeholders played in developing a workable implementation mechanism in his country.

Of the 27 countries that are at various stages of EITI implementation, 17 are in Africa, 4 are in the Americas, 3 in Central Asia, 2 in East Asia, and 1 in the Middle East. This briefing note begins with Azerbaijan—which has published more EITI reports than any other country— in some detail, followed by the EITI experience of five other countries.

Azerbaijan

Azerbaijan has large and mostly untapped hydrocarbon resources. The government has signed two dozen production sharing agreements to date. The State Oil Company of Azerbaijan (SOCAR) was established in 1992 with the merger of two state oil companies, and is party to every production sharing agreement. Production has been ramping up rapidly since 2004.

The government announced its decision to pilot EITI implementation in June 2003. An Ordinance of the Cabinet of Ministers established an EITI Committee in November 2003 as a section of the State Oil Fund of Azerbaijan (SOFAZ). SOFAZ was established by presidential decree in 1999 and receives a portion of revenue flows from oil, with the balance going directly to the state budget. SOFAZ conforms to modern standards of governance in many respects. Amongst others, it is subject to an annual external audit to international standards, and audit reports are published on its multi-language website. SOFAZ is a winner of the 2007 United Nations Public Service Award, the most prestigious recognition of excellence in public service, in the category of “improving transparency, accountability, and responsiveness in the public service.” The EITI Committee is chaired by the Executive Director of SOFAZ and leads the implementation of EITI.

In most countries, civil society organizations (CSOs) have formed EITI coalitions. CSOs have a crucial role in helping the public understand the importance of oil revenues to a country and how those revenues should be managed. CSOs are also generally involved in the process of appointing an administrator (audit-company) to reconcile payments and revenues. In Azerbaijan, CSOs formed the Coalition of Non-Governmental Organizations for Improving Transparency in Extractive Industry (“NGO Coalition”) in May 2004. At the time, the NGO Coalition issued regulations governing its membership, operations, rights and responsibilities, and procedures. The NGO Coalition maintains a dedicated website in English and Azeri to keep the public and the international community closely informed of all the EITI related activities occurring in Azerbaijan [4].

In November 2004, the government, local and foreign companies, and the NGO Coalition signed a memorandum of understanding (MoU) on EITI in Azerbaijan. Today, 24 extractive industries companies and 75 NGOs are signatories to the MoU. The latter include research institutions, environmental groups, lawyers’ associations, women’s and human rights groups, and societies promoting democracy and transparency.

The Executive Director of SOFAZ publicly credited this MoU, which was signed after almost 10 months of intensive consultations, as one of the crucial elements for the success of EITI in Azerbaijan at the London EITI conference in 2005.

The MoU on EITI defined the rules for the EITI process and disclosure of payments made and revenues received. The MoU stated that the EITI Committee would issue two reports annually: a semi-annual one covering January to June, and an annual one covering the entire year. The MoU established a group to select an internationally recognized audit company through a competitive tender to review and aggregate the reports submitted by the government and participating companies.

The NGO Coalition has been participating in the meetings and activities of the parties to the MoU on EITI. It has also held a number of round-table discussions, workshops, seminars, talk shows, radio dialogues, and training sessions. Training of trainers has been conducted on subjects such as production sharing agreement analysis.

The Coalition has also issued written opinions on EITI reports. In 2006, the Coalition carried out two campaigns: “Oil Revenues are Ours” and “Oil Revenues Are For All of Us.” In the first campaign, the

Coalition hosted a competition for journalists to submit articles on analysis of the estimated expenditures of SOFAZ for 2006, the impact of oil revenues on socioeconomic development, or symptoms of Dutch disease (by which an overvalued currency leads to the shrinking of the traditional export sector, such as garments in Cambodia). The second campaign had an extensive outreach component by means of conferences, roundtable discussions, radio programs, newspaper articles, meetings with representatives of local communities, TV talk shows, press conferences, and distribution of books and posters.

Azerbaijan has published five EITI reports to date, covering the period from 2003 to 2006. The reports summarize payments by payment type but not by company. Aggregated payments are reported separately for foreign companies and local companies. The NGO Coalition has issued written opinions on the last three reports. Commenting on the third report, the Coalition noted that it was the first time all of the oil and gas producing companies in Azerbaijan were included, and urged that payments be further disaggregated by company to facilitate identification of sources of discrepancies.

BP, a dominant private oil company operating in Azerbaijan, independently published the payment data it had reported to the EITI audit company for 2004 in its “BP in Azerbaijan Sustainability Report 2005,” while Statoil, another important player in Azerbaijan, annually publishes payments to government in every country in which they have a significant presence, including Azerbaijan, in its “Statoil and Sustainable Development” reports.

Commenting on the fourth report, the NGO Coalition said that non-reporting by one company that had not joined EITI was one of the sources of discrepancies, and urged full participation by all petroleum companies. In October 2006, the non-reporting company joined EITI.

Other Countries

Cameroon

The Republic of Cameroon made a public commitment to EITI in March 2005 at the EITI plenary conference. In announcing the government’s commitment, Finance Minister Abah Abah said that this “decision was the culmination of a carefully considered process,” pointing to the consultation carried out not only with the stakeholders in the country but also at the sub-regional level.

As a demonstration of the government’s commitment to promoting transparency, Minister Abah Abah also pledged that the government would soon start publishing on its website quarterly information on total oil production, prices, and revenues to the government, and that the national oil company, the Société Nationale des Hydrocarbures (SNH), would start posting on its website the main elements of the company’s audit report prepared by a reputable international auditing firm.

In June 2005, the government issued a decree creating a multi-stakeholder committee in charge of implementing EITI. In September 2005, another decree established a Technical Secretariat in the Ministry of Economy and Finance to coordinate the activities of the multi-stakeholder committee. The government published a fully cost work plan and made it widely available.

The government began publishing past audits of SNH as well as production, sales, revenues, expenditures, and transfers to the treasury. Both of these reports are available on SNH’s website [5]. In November 2006, the first EITI report covering July 2000–December 2004 was published. In March 2007, Cameroon became one of a handful of countries to have published a second EITI report, covering 2005.

Ghana

Ghana, an important mining country, committed to EITI in June 2003. The Deputy Ministers of Mines and Finance are two important champions of the process. The Minerals Commission released revenue figures for the first time in September 2003. The governing body of Ghana EITI (GEITI)—the National Committee—is a multi-stakeholder group chaired by the Ministry of Finance and Economic Planning, and consists of government representatives, two civil society representatives, and one representative from the Ghana Chamber of Mines representing the mining industry (See GEITI website [6] for more information). An EITI Secretariat, which coordinates all EITI activities, resides in the Ministry of Finance and Economic Planning.

The first EITI report covering January to June 2004 was issued in February 2007, nearly four years after the government made a public commitment to EITI. Ghana, like Nigeria [3], has chosen to publish payments and revenues by company and payment type. Although company participation was voluntary, the companies that contributed about 99 percent of the royalty payments (which in turn accounted for 89 percent of the total mining revenue stream) participated. In April 2007, The Ministry of Finance and Economic Planning organized a round table to discuss the findings and recommendations of the EITI report and follow-up actions.

Mauritania

Mauritania, an oil producer, established an oil fund in 2006, enabling clear tracking of oil production and revenues. Mauritania also has significant mineral deposits. In September 2005, Prime Minister Boubacar announced the government’s commitment to EITI. The Prime Minister designated a former finance minister as the EITI coordinator. In January 2006, the government issued a decree establishing an EITI National Committee. The Committee has 30 members and draws a number of its members from the mining industry and civil society, including the international NGO Transparency International. In May

2006, the National Committee held a workshop on EITI aimed at engaging the stakeholders involved in the EITI process and discussing the Committee’s future work program. The National Committee maintains its own website [7]. In March 2007, Mauritania released its first EITI report for 2005, covering both petroleum and mining companies.

Guinea

Guinea, rich in mineral resources, committed to EITI in April 2005. In June 2005, a ministerial decree established a Steering Committee responsible for the technical operation of EITI under the Ministry of Mines and Geology. Half of its members are from the government and the other half from mining companies and civil society. The Steering Committee’s mandate as stipulated in the decree is to organize the data in the mining sector; implement financial, sales, technical, economic, and environmental audits; and publish mining revenues in an accessible and comprehensive manner. In July 2005, the Steering Committee drafted an organizational chart for EITI.

In addition to the Steering Committee, the overall structure of EITI includes a Management Committee (five members including the Prime Minister), a Technical Secretariat, and, falling under the Steering Committee, an Executive Committee (five members) and three sub-committees (statistics, audit, and communication and capacity building).

The EITI process in Guinea has been participatory and consensus-based, facilitating active involvement of all three stakeholder segments: government, mining companies, and civil society. Capacity building activities were undertaken in 2005 to help key people in the public institutions and private companies involved in revenue data management understand requirements of the EITI process.

An EITI report covering 2005 has been published. The process of data collection and reconciliation prompted one mining company to pay income tax in 2006 for the first time. EITI has also fostered a culture of discussion among all the key stakeholders, particularly on how revenue allocation and administration for community development are decided, and significant differences in the fiscal terms in mining agreements from company to company.

Peru

Minerals exports account for more than half of Peru’s total exports. The government committed to EITI in May 2005. An EITI Action Plan drafted by a multi-stakeholder committee was adopted and published on Peru’s EITI website in June 2005. In May 2006, the government published an Executive Decree that approved the EITI Action Plan, created an EITI Working Group which represented the entire stakeholders’ constituency, and provided a legal basis to the implementation of EITI. At the request of industry and CSOs, the Ministry of Energy and Mines has drawn up a Ministerial Resolution establishing criteria to ensure the legitimacy and qualifications of civil society representatives on the Working Group. In December 2006, the EITI Working Group was established. A unique feature of Peru’s EITI process is its plan to carry out audits at the sub-national as well as the national level.

Observations

The experience in Azerbaijan and elsewhere suggests that the more disaggregated the reporting, the more the stakeholders benefit from the process; disaggregation makes it easier to identify where discrepancies are occurring. Azerbaijan’s EITI report for 2005 reinforces the point made in [3] that, if even one company does not submit data, revenues and payments cannot match and it will be more difficult to identify sources of discrepancies. Legislating participation in EITI is one way of ensuring full participation.

Guinea’s experience, as with Nigeria’s [3], demonstrates that, by raising awareness and publicizing independent monitoring of company payments, more effective revenue collection may ensue. This not only increases government revenue, but also contributes to creating a level playing field for companies operating in the country. In the long run, such an outcome helps to strengthen the sector and make it more efficient.

References

[1] EITI website www.eitransparency.org. Email eitiinfo@eitransparency.org.

[2] World Bank. 2007. “Extractive Industries Transparency Initiative.” Petroleum Sector Briefing Note No. 4.

[3] World Bank. 2007. “Country Experience with EITI – Part 1.” Petroleum Sector Briefing Note No.5.

[4] The Coalition of Azerbaijan Non-Governmental Organizations. www.eiti-az.org/ts_gen/eng/index.htm.

[5] www.snh.cm.

[6] GEITI. www.geiti.gov.gh.

[7] www.mauritania.mr/itie.

(Source: The World Bank Newsletter, August 2007)

• Country Experince with EITI-Part I

Related posts:

• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• April 8, 2009 — Avoiding the Resource Curse (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)
• June 15, 2009 — Vietnam’s petroleum company met Sok An (0)

We are looking at close to a billion dollars saved,” the Executive Director of Nigeria EITI (NEITI) told news reporters in January 2007, attributing the additional revenues to the close monitoring of the oil companies in 2004 and 2005 under NEITI [1]. EITI, through multi-stakeholder partnerships, supports improved governance in resource-rich countries through the verification and full publication of company payments and government revenues from oil, gas, and mining [2, 3].

If the criterion for being resource-rich is that at least 25 percent of the government’s total revenue or of total export proceeds is from oil, gas, or mining, then 50 countries were resource-rich based on the data from 2000–2005. The region with the largest number of resource- rich countries was Africa (18), followed by the Middle East (11), the Americas (8), Central Asia (6), East Asia (5), and Europe (2). The resource-rich East Asian countries were Brunei, Indonesia, Vietnam, Mongolia, and Papua New Guinea, of which the last two are mineral-rich. Other Asian countries, such as Timor-Leste and Cambodia, are already resource-rich or have the potential to become so in the future. To date, 27 countries have publicly committed to EITI, including Mongolia and Timor Leste in East Asia. Eight countries have issued one EITI report or more. No two EITI programs are alike; each country has adapted and added to the EITI criteria to suit its particular circumstances and objectives.

In terms of scope, the country with the widest coverage is arguably Nigeria, perhaps reflecting the desire and determination to redress decades of oil revenue mismanagement (see [4]). NEITI takes EITI as a starting point and tackles a host of other issues that EITI criteria do not cover (see “EITI in Context” in [3] for what the criteria do not cover). São Tomé and Príncipe and Timor-Leste have legislated revenue disclosure. This briefing note covers Nigeria in some detail on account of its comprehensive coverage, extensive outreach to civil society, and the lessons it offers for the management and accountability of the petroleum sector. It is the first of a two-part series describing the experience of these and other countries.

Nigeria

Nigeria has a long history of oil production and is Africa’s largest oil producer. Oil revenue accounts for more than 40 percent of the country’s gross domestic product (GDP), 80 percent of government revenue, and 90 percent of total exports. President Obasanjo committed the government of Nigeria to EITI in November 2003 and launched NEITI in February 2004.

The NEITI process consists of financial, physical, and process audits. Physical and process audits are not required by the EITI criteria [3], but NEITI has included them to strengthen governance in the sector. The first complete set of reports, covering the six-year period from 1999 to 2004, was published in April 2006; about 2½ years after Nigeria first endorsed EITI. The report represented the most comprehensive audit of the petroleum sector in Nigeria’s history. The administrator (for reconciling payments and revenues; see [3]) for the audit covering 2005 is being contracted. The tender for the 2006 audit, which will include the so-called value-for-money audit of petroleum sector processes— examining whether expenditures are reasonable and prudent—will be issued in the second half of 2007.

The financial audit is at the heart of EITI. The principal benefit streams examined in the 1999–2004 audits were:

• Oil related flows: petroleum profit tax, royalty, gas flaring penalty, reserves additional bonus, and signature bonus
• Non-oil related flows from the petroleum sector: value-added tax, education tax, and withholding and PAYE (pay as you earn) tax to federal and state governments
• Proceeds of sale of crude oil and gas allocated to the government (typically the largest of all inflows to the government), and cash-call payments made by the government (representing financial outflows), in accordance with the government’s equity share in joint venture operations.

The audit covered material payments from 22 companies as well as government financial flows through seven joint venture operations. The findings were reported by company and payment type. This audit also published a report entitled “Issues in Government Financial Systems,” which outlined the difficulties encountered during the financial audit and made recommendations to improve government accounting for better management and control of key revenue sources in the petroleum sector. Subsequent work by the administrator identified weak recording practices in the government agencies as the primary cause of the discrepancies, and reduced the unexplained discrepancies to 0.01 percent [5]. The final audit report was released to the public in December 2006. Inter-agency reconciliation processes have been simplified and improved as a result of using the reporting templates.

The physical audit carried out a material balance on hydrocarbons (oil and gas) in the country—that is, tracing the volume of hydrocarbons from production to the final point of sale. The audit covered hydrocarbons produced, lifted, flared (for gas), lost, refined, and exported; refined products imported; and all refined products supplied on the domestic market. Significant inconsistencies in volumes were found as well as shortcomings in metering and book-keeping. The audit found a systematic loss of crude oil between the wellhead and terminals. Fluctuations in the pipeline flow rates suggested thefts at night [5]. The audit report made several recommendations to strengthen physical accounting.

The process audit reviewed the transparency and efficiency of refinery operations and refined product importation; capital and operating expenditures; oil and gas licensing processes; the process for marketing natural gas; and the process for marketing the federal government’s equity crude oil. A large number of recommendations were made in a series of reports issued under process audits. Thanks to public-awareness raising and publicity in the media, issues such as transparency of the oil licensing rounds have been widely discussed.

In response to these findings and recommendations, President Obasanjo in May 2006 directed NEITI to set up and chair an Inter-Ministerial Task Team to address the problems identified in the audit, including institutional weaknesses, poor record-keeping practices, inadequate accounting systems, and poor interface among government entities. The Task Team was constituted and began meeting in August 2006. The relevant government agencies proposed their own remediation measures, set up study teams, and established an inter-agency committee to ensure consistency of information across the government. Steps are being taken to provide assistance to government agencies to strengthen capacity for interfacing with each other. NETI is now being extended to cover the mining sector [5]. Additional information on NEITI activities is available on the NEITI website [6].

The champion of EITI is the Director General of the Nigeria Geological Survey Agency. A 28-member National Stakeholders Working Group (NSWG), established in February 2004 by President Obasanjo, steers implementation. NSWG draws members from civil society (2 representatives), media (1), government (14), local and multinational companies (3), the private sector (4), the National Assembly (2), and the Houses of Assembly at the regional government level (2). The NEITI Secretariat coordinates the work of NSWG, which has technical, legislative, focal (for capacity building), civil society, and media teams. The civil society team engages the wider public and helps build capacity within civil society organizations (CSOs). Capacity building is aimed at helping CSOs understand how EITI works so that they can ask the right questions; educate their constituency and the general public about the oil industry and its revenues; and gain a better understanding of the data and information contained in EITI reports so that they can disseminate information more effectively. NSWG recognizes the limitations of traditional media (newspapers, television, radio) for rural populations and communication difficulties in a country with more than 500 languages, and places emphasis on dissemination of information through a grassroots-based communication strategy and the engagement of rural communities and regional CSOs. NEITI has conducted several “road shows” around the country to interact with civil society representatives and disseminate information, including audit findings. Training of government leaders, legislature, and civil society on petroleum economics, the flow of funds, and the role of NEITI is underway.

In February 2006, a memorandum of understanding (MoU) was signed between NSWG and CSOs with a view to advancing civil society’s participation in NEITI, ensuring independence of CSOs in the NEITI process, helping to build CSO capacity, and ensuring proper internal communication among CSOs. Civil society involvement in EITI in Nigeria has helped government ensure that the EITI process leads to enhanced revenue collection, encourages all companies to provide revenue data, helps identify possible sources of oil theft, and contributes greatly to strengthening the quality of public debate about oil issues nationally. In June 2007, the government passed an NEITI Bill into law. This legislation guarantees mandatory annual audits of the extractive industries sector; oil companies will be legally required to disclose payments; and the recently established Oil Revenue Monitoring unit will be made formally independent of the Finance Ministry and merge with the NEITI Secretariat.

Legislative Approach to Disclosure

São Tomé and Príncipe endorsed EITI principles in June 2004. The country is not yet an oil producer, but has already taken significant steps to write transparency provisions into legislation. An Oil Revenue Law was unanimously approved by the National Assembly and signed by the president in December 2004. This law requires all oil payments to be deposited directly into a national oil fund held by an international custodial bank. Deposits, withdrawals, and holdings of the fund are made public through a newly established public information office and by posting on the internet. The law requires competitive tenders for oil contracts, makes all oil contracts public, mandates the inclusion of anticorruption and transparency provisions in contracts, and declares null and void those confidentiality clauses in oil contracts that are at variance with the transparency requirements of the law. There is therefore a firm legal basis for São Tomé and Príncipe to implement EITI once commercial production starts.

Timor-Leste is a new natural gas producer. Like São Tomé, Timor-Leste has also taken significant steps to ensure transparency in its petroleum sector, and involved civil society in the process. In October 2004, the government released a “Public Consultation Discussion Paper on Establishing a Petroleum Fund for Timor-Leste.” A series of public consultation sessions were held in every district of the country and written comments were submitted. The government released a draft Petroleum Fund Law in January 2005 and further public consultation followed, including testimonies given by CSOs before the Parliament. The Law was passed unanimously in June 2005.

The law requires all revenues associated with petroleum operations to be deposited into the newly created Petroleum Fund. The law cites transparency as a fundamental principle. It stipulates that quarterly reports on the performance and activities of the Petroleum Fund must be published, and that an internationally recognized accounting firm be appointed as an independent auditor of the Petroleum Fund. The auditor’s annual report, which states the aggregate amount of payments made by each payer, must also be published. A consultative council that includes members of civil society and the business community is tasked with advising the Parliament on matters related to the Fund’s performance and operation, and effective use of appropriations from the Fund. According to the law, monies from the Fund spent by the government (in accordance with the “estimated sustainable income”) must flow through the state budget.

The government of Timor-Leste has set up a Petroleum Transparency website in English, Portuguese, and Tetum (a local language) [7]. Posted on the website are the quarterly reports on the Petroleum Fund, various laws related to the petroleum sector (Petroleum Act, Petroleum Taxation Act, Petroleum Fund Act), model production sharing contracts, and sample contracts and their amendments, as well as an earlier version of the Petroleum Fund Act and various comments submitted on the Petroleum Fund discussion paper. Such commitment to disclosure by the government helps build a general climate of accountability and transparency in the sector. The first meeting of the national EITI working group was recently convened in Dili.

Other Countries

Mongolia

Mongolia is the second of the two East Asian countries implementing EITI. A significant producer of copper and gold, Mongolia committed to EITI in December 2005. It has made rapid progress in the last 18 months and has established a multi-stakeholder working group as well as a work plan. Mongolia is currently in the process of setting up a secretariat, whose first task is to appoint an administrator.

Kazakhstan

Kazakhstan, the largest oil producer in Central Asia, committed to EITI in June 2005. Kazakhstan is where Mongolia is in the EITI process, having created a multi-stakeholder working group and a work plan, and being in the process of establishing a secretariat.

Gabon

Oil accounts for about one half of GDP, two thirds of government revenue, and 80 percent of total exports in Gabon. Gabon committed to EITI in March 2005 after issuing a ministerial decree to establish an EITI Working Group a month earlier. The Working Group includes representatives of all administrations involved in oil revenue collection and management. A stakeholders’ group responsible for EITI implementation is chaired by a representative of the President’s office and includes representatives from the prime minister’s office, ministerial departments, civil society, the oil sector, and the mining sector. A website was launched in October 2005 and the government published, in December 2005, an EITI report covering 2004. The stakeholders observed that the first EIEI report omitted a major revenue stream, which was subsequently included in the second report. However, not all oil companies have reported, and the administrator has not made attempts to reconcile the discrepancies between payments and revenues.

Observations

Nigeria’s first EITI report was ambitious and covered six years and a range of issues beyond payments and revenues. By publicly highlighting the weaknesses that needed attention, NEITI has already achieved the objective of quantifying where the gaps are, identifying the likely causes, and recommending remedial actions. Nigeria’s experience also suggests that, by providing greater scrutiny over revenue collection, EITI can lead to increased (or more efficient) revenue collection.

Gabon’s experience shows that one barrier to providing an adequate level of detail in reporting is poor availability of data on financial flows. It also shows that, absent a legal obligation to report, participation of all companies, without which meaningful comparison of payments and revenues cannot be made, may be difficult.

References

[1] Vanguard. 2007. “Extractive Industries Transparency Initiative saves $1 billion.” January 2.

[2] EITI website www.eitransparency.org. Email eitiinfo@eitransparency.org.

[3] World Bank. 2007. “Extractive Industries Transparency Initiative.” Petroleum Sector Briefing Note No. 4.

[4] World Bank. 2007. “Avoiding the Resource Curse.” Petroleum Sector Briefing Note No. 3.

[5] Bright Okogu. 2007. “Implementing EITI: The Nigerian Experience.” www.geiti.gov.gh/downloads/nigerian_experiences_with_EITI_presentation_bright_okogu.pdf.

[6] NEITI. www.neiti.org.

[7] www.transparency.gov.tl.

(Source: The World Bank Newsletter, Special Supplement: Gas & Oil, July 2007)

Related posts:

• April 8, 2009 — Avoiding the Resource Curse (0)
• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)
• August 10, 2009 — Refining Crude Oil – Part 1 (0)

How have some resource-rich countries managed to avoid the resource curse? Nigeria and Indonesia make an interesting comparison. They exported comparable amounts of oil in the first half of the 1980s. Both have large populations and regional and ethnic tensions. Yet Nigeria, despite being the world’s sixth largest oil exporter in 2005, has one of the poorest populations in sub-Sahara Africa and come to epitomize what can go wrong with oil wealth, while economic growth in Indonesia until 1996 has won praise. And this enormous difference in outcome is not because Indonesia had inherent advantages over Nigeria before the first oil boom of 1973–74. In fact, the initial conditions in Indonesia were anything but favorable: a military regime that came into power in 1966, a low adult literacy rate, high levels of ethnic and linguistic diversity which can lead to conflicts (see [1] for the impact of oil wealth on civil strife), and pervasive corruption.

This note describes and contrasts some of the policies implemented by Nigeria, Indonesia, Malaysia, and Botswana in response to large inflows of resource revenues, and their consequences.

Nigeria

In 1970, Nigeria had an active private sector and a large labor force, holding great promise to become the region’s economic power house. Successive governments have embraced three common objectives: economic growth, greater domestic participation in both the oil and nonoil sectors, and more equitable distribution of income across ethnic groups and regions. As the first oil boom of 1973–74 began to generate substantially larger state revenues, the government initially tried to save excess income. But this attempt at saving was short-lived. As the size of the new oil wealth became widely known, political pressures to spend all of it at home mounted and the government soon accelerated spending as if the high oil prices were permanent.

Budget deficits grew, and, encouraged by projections of continually rising oil prices, the government began to borrow abroad. These foreign debts soon became unsustainable.

During 1975–1980, the government gave priorities to infrastructure (transport and communications); mining and manufacturing; agriculture and water supply; and health, education, and housing, in that order. Spending on primary education was greatly increased, and one major achievement was the use of oil income to fund almost universal primary education. Although self-sufficiency in agriculture was the desired goal, investment in agriculture declined. In other areas, many projects were quickly started without due attention to their economic viability, coordination, or sequencing, and with few safeguards against waste and corruption.

The second oil boom of 1979–80 prompted another spending spree, giving rise to higher salaries and new investment projects, including construction of the new inland capital, Abuja. The lion’s share of investment in agriculture and industry went to a few large, high-cost projects such as steel, irrigation, and fertilizer production. The policy of maintaining a relatively low interest rate, combined with rising wages and the appreciating exchange rate (see [1] for a discussion on Dutch disease), encouraged capital-intensive industries based on imported inputs. These distortions and inefficiencies in the economy slowed down competitive industrialization and the share of industry in gross domestic product (GDP) actually fell from 19 percent in 1974 to 10 percent in 1994.

After 1980, oil revenues collapsed and real income per person fell sharply. The income from oil exports in Nigeria was among the most volatile on account of fluctuating oil production—exports more than halved between 1979 and 1983—in addition to oil price volatility, plummeting from a high of US$25 billion in 1980 to a low of $6 billion in 1986. During the oil booms, the Nigerian currency appreciated and agricultural exports halved. Poor policy choices amplified the adverse effects of oil revenue volatility, making the investment climate extremely unattractive.

In the face of mounting economic difficulties, the new military government that came into power in 1983 imposed a program of fiscal austerity, including across the board budget cuts, reduced imports, and foreign exchange rationing. The wage bill could not be reduced for political reasons, and budget cuts resulted in many unfinished projects. Continuing deficits and emerging debt-servicing problems led the government to adopt a structural adjustment program in 1986. But downsizing the public sector and improving fiscal administration again proved politically difficult. The third oil boom of 1990 led to more public spending [2].

Like many large oil exporters, Nigeria has historically subsidized fuel prices. This has not only carried an enormous cost, but led to a widespread black market, smuggling of subsidized fuels to neighboring countries, inadequate financing to maintain and modernize domestic refineries, and frequent fuel shortages coupled with price spikes that hurt consumers and especially the rural poor. Cheap fuels have also encouraged non-essential and inefficient fuel consumption. Increasing fuel use, together with smuggling, raise “apparent” domestic demand—fuels smuggled out of the country are not actually consumed on the domestic market but appear in the statistics as domestic consumption—and cut oil exports, reducing revenue to the government.

Agricultural performance in the 1970s and 1980s fell far short of the goal of self-sufficiency. Despite efforts under the “Operation Feed the Nation” in the 1970s, Nigeria—once a modest exporter of farm products—became a large net importer of food by the early 1980s. A lack of clarity in land ownership rights; public spending targeting urban rather than rural infrastructure; cheap food imports thanks to the stronger exchange rate; loss of skilled workforce to migration to urban areas; and inefficiency in the distribution of domestic inputs and technical support contributed to this disappointing outcome. The quality of economic policy in Nigeria progressively deteriorated after 1990. Business activity was affected by personal ties and endemic corruption. Some suspect General Abacha alone of having stolen an estimated US$2.2 billion of government revenue during his presidency between 1993 and 1998 [3].

Nigeria returned to civilian rule following the elections of 1999 and has been making concerted efforts to tackle corruption and accelerate development. In 2004 an Economic and Financial Crimes Commission was established, which began trying people for corruption in a civil court for the first time. The government has adopted an oil-price-based fiscal rule that mandates saving excess oil income when world oil prices rise above a reference price. Allowing corruption to fester for decades, Nigeria has not found it easy to root it out. Oil still provides some 85 percent of the government’s revenue and continues to be a source of strife and mismanagement. Nigeria has publicly demonstrated its commitment to revenue transparency by launching the Nigeria Extractive Industries Transparency Initiative, which will be discussed in future briefing notes.

Indonesia

In the mid-1960s, Indonesia was one of the poorest countries in the world, with large government deficits and hyper-inflation nearing 1,500 percent a year at one point. President Suharto came into power in 1966. Despite being a military one with high concentration of power in the president, the Suharto government gave priority to economic growth, emphasizing infrastructure, education, capital-intensive industry, and, above all, agriculture to which an unusually high proportion of government spending was allocated.

President Suharto appointed a team of five economic advisers, all academics drawn from the Faculty of Economics at the University of Indonesia. They were technocrats, well educated and competent, and exerted considerable influence. Focusing on macroeconomic stability and tight control over inflation and budget deficits, the government brought down inflation drastically by 1969. President Suharto’s 31-year grip on power, which could have led to economic failure, enabled a long-term view and continuity in policy-making.

Agriculture, which accounted for three-quarters of total employment in the early 1960s, played a key role in the country’s growth and poverty reduction. During the first oil boom, the government allocated about 20 percent of its investment expenditure to agriculture, compared to only 2 percent in Nigeria. The government gave large subsidies to inputs (fertilizers, pesticides); invested in irrigation, roads, and schools in rural areas; and helped stabilize rice prices. Fortunately for Indonesia, the timing of these policies coincided with the Green Revolution, which introduced high-yielding crop varieties. Oil revenues funded fertilizer subsidies and spread of high-yielding varieties. These helped raise rice yields in the late 1970s and early 1980s and Indonesia turned from having to import almost a third of the world’s traded rice in some years to self-sufficiency by 1985, a goal earlier considered unattainable by many.

The country was also “helped” by Pertamina’s financial scandal of 1975. Pertamina, Indonesia’s national oil company, failed to repay its loans in 1975 after making extensive and diverse business investments and accumulating some US$10.5 billion in debt, equivalent to almost 30 percent of Indonesia’s GDP. This scandal greatly diminished Pertamina’s reputation and political influence, delayed overly ambitious and risky investments in the oil sector (and when oil prices fell in the 1980s, there was still time to cancel the planned projects), and strengthened the hand of reformers.

When oil prices fell in the early 1980s, the government reacted swiftly with a series of measures that combined expenditure reduction, exchange rate devaluation in 1983 and 1986, and economic reform. The response was dramatic. Between 1983 and 1992, the share of manufactures in total merchandise exports rose from 7 percent to nearly 50 percent. Some officials have even come to regard the collapse of world oil prices as a blessing in disguise.

This is not to say that all economic policies were sound. The government has maintained large fuel price subsidies (prices were more than doubled in 2005, but the total subsidy bill in 2006 is still an estimated US$7 billion) and this has had similar negative effects to those in Nigeria. The financial crisis of 1997–98 affected Indonesia more than other Asian economies, and some analysts argue that the way the country’s rapid growth interacted with weak institutions contributed to the severity of the crisis [4]. Nevertheless, Indonesia illustrates how a major oil producer has overcome unfavorable initial conditions and temptations to squander oil windfalls to achieve impressive economic gains.

Malaysia is endowed with diversified natural resources that include oil, rubber, tin, and palm. Like Indonesia and Nigeria, Malaysia faced ethnic tensions, but the government deliberately pursued a policy of improving the welfare of the majority group, Buminputeras, who were rural and poorer than other groups.

A critical element of success was the high savings rate that made capital available for investment. Households were frugal by nature, and in addition workers were required to contribute to a compulsory savings scheme. Government expenditures favored education, housing, and health, and achieved a geographically balanced distribution.

Malaysia promoted export-oriented manufacturing from the early 1970s. One unsuccessful policy was use of oil income in the early 1980s to launch heavy and chemical industries (vehicles, steel, and cement) by public sector companies enjoying government protection. This policy led to economic difficulties. The size of the public sector doubled between 1966 and 1981. The recession of the mid-1980s returned the country to private sector- led economic development.

Instead of import substitution, Malaysia pursued economic diversification and export-oriented industrialization. Sensible economic policies were formulated and implemented by professional civil servants, academics, and technocrats. In the early stage of development, the government focused on labor-intensive industrialization utilizing workers from rural areas. Fortunately, around that time, multinational companies were relocating manufacturing to developing countries where wages were lower. To supply skilled workers to the rapidly expanding manufacturing sector, the government allocated a substantial portion of the budget to education.

As a first step, the government provided free primary education. Secondary education was expanded in line with progress made in primary education, and the enrollment tripled from 1960 to 1990 [5].

At the time of independence in 1966, Botswana was extremely poor. Botswana is not an oil producer but is the world’s largest producer of gem-quality diamonds. A small country, Botswana ranks among the most successful resource-rich countries, thanks to prudent fiscal policies toward managing revenue generated from diamond mining. Much of the diamond income has been spent on infrastructural development, education, health, and agriculture, and little on “prestige” projects.

To assess its fiscal performance, the government has constructed an index called the budget sustainability ratio. It is the ratio of non-investment spending (that is, consumption) to non-mineral revenue. A ratio greater than unity indicates that the government is using mineral revenues to finance consumption, which is unsustainable in the long run.

In 1972, in the same year the commercial production of diamonds began, the government established a fund to save excess revenues abroad to finance budget deficits in times of need, and introduced an incomes policy specifically designed to prevent mining wages from pulling up general wages. Consensus politics has evolved and taken hold in Botswana, leading to a high level of transparency in public revenue collection and expenditure. The ruling elite has left technocrats and professional civil servants (who were among the best educated) alone to implement sensible policies.

The government has historically had a reputation for being relatively clean, but a number of scandals broke out in the early 1990s. In response, the government established a Directorate of Corruption and Economic Crime in 1994 to good effect. Corruption has remained well below levels seen in most other developing countries. Table 1 ranks countries in order of increasing corruption according to a perception index compiled by Transparency International. In addition to the countries surveyed in this note, Saudi Arabia—the world’s largest oil exporter—and Iceland—perceived to be the least corrupt—are included for comparison.

Conclusions

Until recently, the economic trajectory of Nigeria reflected many policy errors and deteriorating governance generally considered responsible for the natural resource curse: large expenditures on dubious prestige projects, a growing public sector that is not able to contract in times of low oil prices, and outright thefts of oil revenue, to mention a few. In contrast, Indonesia has managed to achieve a four-fold increase in GDP per person through political stability, good economic policy, rapid productivity improvement in agriculture, poverty-focused policies, and an effective response to large oil revenue volatility. Indonesia, Malaysia, and Botswana have all relied on highly trained technocrats and given them relative autonomy to run the economy. These examples illustrate that the resource curse is not inevitable, but also that a strong political will and commitment to sound economic policies, sustained over many years, are needed to avoid it.

References

[1] World Bank. 2007. “Oil and Gas: A Blessing or A Curse?” Petroleum Sector Briefing Note No. 2.

[2] Amuzegar, Jahangir. 1999. Managing the Oil Wealth: OPEC’s Windfalls and Pitfalls. New York: I.B. Tauris Publishers.

[3] Pan, Esther. 2005. “The Pernicious Effects of Oil.” Council on Foreign Relations. www.cfr.org/

publications/8996/pernicious_effects_of_oil.html.

[4] Temple, Jonathan. 2001. “Growing into trouble: Indonesia after 1966.” http://ksghome.

harvard.edu/~drodrik/Growth%20volume/ Temple-Indo.pdf.

[5] Auty, R.M. Resource Abundance and Economic Development. 2001. Oxford: Oxford University

Press.

(Source: The World Bank Newsletter, Oil and Gas, May 2007)

Related posts:

• April 8, 2009 — Country Experience with EITI – Part 1 (0)
• June 1, 2009 — Country Experience with EITI – Part 2 (0)
• March 30, 2009 — Oil Resource Holds Hope for Cambodia’s Future Wealth (0)
• March 30, 2009 — Introduction to Oil and Gas (0)
• April 3, 2009 — Extractive Industries Transparency Initiative (0)
• July 27, 2009 — Contracts for Petroleum Development – Part 3 (0)
• July 2, 2009 — Contracts for Petroleum Development – Part 2 (0)
• July 12, 2010 — Explaining spending oil and gas revenues remained unclear (0)
• October 27, 2009 — Refining Crude Oil – Part 2 (0)
• August 10, 2009 — Refining Crude Oil – Part 1 (0)