Monday, October 31, 2011

The major energy sources in the United States

The major energy sources in the United States are petroleum (oil), natural gas, coal, nuclear, and renewable energy. The major users are residential and commercial buildings, industry, transportation, and electric power generators. The pattern of fuel use varies widely by sector. For example, oil provides 94% of the energy used for transportation, but only 1% of the energy used to generate electric power. Understanding the relationships between the different energy sources and their uses provides insights into many important energy issues.

Primary energy includes petroleum, natural gas, coal, nuclear fuel, and renewable energy. Electricity is a secondary energy source that is generated from these primary forms of energy.

Primary energy sources are commonly measured in different units: barrels (= 42 gallons) of oil, cubic feet of natural gas, tons of coal. To compare across fuels, we need to use a common unit of measure. The United States uses Btu, or British thermal units, which measure fuel use by the energy content of each fuel source.

Total U.S. energy use in 2010 was 98 quadrillion (=1015, or one thousand trillion) Btu. One quadrillion Btu, often referred to as a "quad," therefore represents about 1% of total U.S. energy use.

In physical energy terms, 1 quad represents 172 million barrels of oil (8 to 9 days of U.S. oil use), 50 million tons of coal (enough to generate about 3% of annual U.S. electricity use), or about 1 trillion cubic feet of natural gas (equal to 4% of annual U.S. natural gas use in 2010).

The number of quads used in 2010 from each primary energy source is shown in the pie chart on the left. Petroleum (oil) provides the largest share of U.S. primary energy, followed by natural gas, coal, nuclear energy, and renewable energy (including hydropower, solar, geothermal, wind, and biomass).

Primary energy is used in residential and commercial buildings (including homes, businesses, schools, and churches), in transportation, and by industry. Primary energy is also used to generate electricity. The bar chart shows the amount of primary energy used in each of these sectors. As you can see, electric power generation is the largest user of primary energy, followed by transportation.

The electric power sector uses primary energy to generate electricity, which makes electricity a secondary, rather than a primary, energy source. Nearly all electricity is then used in buildings and by industry. This means that the total levels of energy used by residential and commercial buildings, industry, and transportation are actually higher than the amounts shown on the graphics when electricity is added in.

The lines in the figure below connecting the primary-energy-sources on the left with the demand-sectors on the right summarize the source-sector linkages in the U.S. energy system. For example, because all nuclear energy is used in the electric power sector to generate electricity, and nuclear represents 21% of the primary energy used by that sector, the line between nuclear energy and the electric power sector shows 100% on the nuclear (supply source) side and 21% on the electric power (demand sector) side.

The mix of primary energy sources varies widely across demand sectors. Energy policies designed to influence the use of a particular primary fuel for environmental, economic, or energy security reasons often focus on sectors that are major users of that fuel.

For example, because 71% of petroleum (oil) is used in the transportation sector, where it provides 94% of the total energy used, policies to reduce oil consumption have tended to focus on the transportation sector. These policies usually seek to increase fuel efficiency or promote alternative fuels. Ninety-two percent of coal, but only 1% of oil, is used to generate electricity, suggesting that policies affecting electricity generation are likely to have a much larger impact on coal use than oil use.

Some primary energy sources, such as nuclear and coal, are entirely or predominately used in one sector. Others, like natural gas and renewables, are more evenly distributed across sectors. Similarly, while transportation is almost entirely dependent on one fuel (oil), electric power uses a variety of fuels.

The electric power sector has seen large changes in the fuel mix. A little over 50 years ago, nuclear energy played no role in electric power generation, but in 2010, nuclear energy provided 21% of the energy used to generate U.S. electricity. Oil provided a growing share of energy for electric generation through the 1960s, but its share has declined to 1% in 2010 since peaking at 18% in 1973.

Thursday, October 27, 2011

Brazil's Major Role in Long-Term Non-OPEC Growth

World's largest increases in oil production in the coming decades will be in Brazil's response. Petrobras advanced in seismic imaging that has enabled the discovery of offshore "pre-salt" deposits of oil in Brazil's Campos and Santos Basins (figure below). These pre-salt fields, so-called because they lie under massive layers of salt, are located 18,000 feet below the ocean floor under more than 6,000 feet of salt. Brazil's crude oil production exceeds  2.1 million barrels per day (bbl/d)  and lease condensate. Pre-salt development, coupled with the ability to meet a large share of domestic demand with biofuels, is projected to transform the country into a major oil exporter since Brazil became a net exporter in 2008.

Campos and Santos basins

It has been projected that the largest increases in conventional liquids production outside of the Organization of Petroleum Exporting Countries (OPEC) will occur in Brazil (Figure Cumulative Growth). It has been estimated that Brazilian conventional production to grow to 4.8 million bbl/d in 2035. This means that 40 percent of non-OPEC growth over the projection period and 14 percent of total world production growth in conventional liquids will come from Brazil.
Cumulative non opec conventional production 

After 2015, the EIA liquids supply projections are based on resource availability and the economic viability of production. While a massive resource base underlies EIA's projections of Brazilian production growth, the exact magnitude of the country's reserves is still unclear. According to Oil & Gas Journal, Brazil's proven oil reserves are currently estimated at 12.9 billion barrels, but this total does not include major pre-salt fields. Estimates of Brazil's pre-salt reserves have varied widely. In 2008, Haroldo Lima, Director General of Brazil's National Petroleum Agency, stated that the pre-salt could contain between 50 and 70 billion barrels of oil. In January 2011, Petrobras announced its assessment that the Lula and Cernambi fields contained 6.5 billion and 1.8 billion barrels of commercially recoverable oil, respectively. It will be some time before Brazil's pre-salt reserves are fully estimated. However, knowledge of precise reserve volumes is not critical to assessing the viability of Brazil's proposed expansion of production in the coming years.

Three major categories of challenges introduce uncertainty into estimates of Brazilian production growth: financial, operational, and legislative. The costs of Brazil's pre-salt development will be immense. In July 2011, Petrobras released its 2011-2015 business plan, which outlines a $224.7 billion investment program focused heavily on exploration and production. The plan calls for a reduction in downstream investment and divestiture of foreign assets to facilitate a sharpened domestic upstream focus. Notwithstanding Petrobras' 2010 share offering of $67 billion (the largest ever), the company will still need to maintain significant operating cash flow to achieve its goals.

In addition to costs, pre-salt development presents numerous technical and operational challenges stemming from the scale of the endeavor. The reserves are located more than 150 miles off Brazil's coast, making them difficult for pipelines and people to reach. Petrobras plans to purchase 45 floating production, storage, and offloading (FPSO) vessels to extract the pre-salt oil - currently fewer than 100 such ships exist in the world. Expanding Brazilian production will also require additional human capital. These challenges will be especially difficult because, unlike other Brazilian offshore ventures, Petrobras will be the exclusive operator of future pre-salt fields. Petrobras plans to train more than 240,000 technical professionals to work in the petroleum industry in the coming decade - the company currently employs just over 80,000 people.

While production is underway in some of Brazil's pre-salt fields, the scaling up of production also depends on the Brazilian government's ability to arrive at an agreement on the distribution of future oil revenues. At issue is the division of revenues between the federal government, states, and municipalities. Past arrangements have predominantly benefited oil-producing states; non-producing states now want a larger share. Because revenue distribution must be set in advance of bid rounds, Brazil will not be able to conduct further auctions of pre-salt blocks until these issues are settled.

While all of these challenges introduce some uncertainty into projections of Brazilian production, they are unlikely to hinder pre-salt development.

Tuesday, October 25, 2011

A giant gas discovery offshore Mozambique

In March 2006 ,Eni was awarded a licence for the exploration of an offshore area situated in the northern part of the country, approximately 2'000 kilometres north of the capital of Maputo. The Block, known as Area 4, is located in deep water up to a depth of 2,6000 metres in the Rovuma Basin and covers an area of 17,646 square kilometres. Area 4 is located in a previously unexplored geological basin, and this operation is part of Eni's strategy to identify new areas with a high mining potential.

Eni announces a giant natural gas discovery at the Mamba South 1 prospect, in the Area 4 Offshore Mozambique. The discovery well encountered a total of 212 meters of continuous gas pay in high-quality Oligocene sands.

Mozambique Offshore Areas by company

The Mamba South 1 discovery well is located in water depths of 1585 meters approximately 40 km off Cabo Delgado coast, in the Northern offshore of Mozambique. This is the first exploration well in Area 4. Results exceed pre-drill expectations and confirm the Rovuma Basin as a world-class natural gas province.

The well will be drilled to reach an expected total depth of around 5000 meters. After completion of drilling and testing activities, the rig will move to drill the second commitment well, Mamba North 1.

Eni considers that this impressive discovery can lead to at least 15 tcf of gas in place in the Mamba South Area where the potential of the Tertiary Play that exists in Area 4 will be further assessed under the present drilling.

Location of Area 4 Mozoabique

The outstanding volume of natural gas discovered will lead to a large scale gas development with a combination of both export to regional and international markets through LNG and supply to the domestic market. This will support the industrial and economic growth of the Country.

Eni would proceed to develop the field and first gas production was possible in 2016. It is cautioned that the estimate for the size of the discovery referred only to resources, not proved reserves.

Mozambique’s location on the Indian Ocean, and a large port at the capital, Maputo, makes the country ideally suited to supplying liquefied natural gas to Asian buyers, according to Eni. “Mozambique is very well placed to serve the Pacific market – India, China, Thailand – which is the region where consumption of gas is growing most rapidly and prices are highest,” Eni said.

The amount of gas discovered “might justify” the construction of “up to three” liquefier plants in Mozambique, Eni added. Each would require investment of some $5bn.

The Mamba South discovery marks a new milestone for Eni since the resource potential assessed with the first exploration well makes it the largest operated discovery in the company's exploration history. The exploration success in Mozambique expands the leadership of Eni in Africa by opening a new eastern front of activities.

Eni is the operator of Offshore Area 4 with a 70-percent participating interest. Co-owners in the area are Galp Energia (10 percent), KOGAS (10 percent) and ENH (10 percent, carried through the exploration phase).

Thursday, October 20, 2011

Australia Energy Report

Australia has considerable petroleum, natural gas and coal reserves and is one of the few countries belonging to the Organization for Economic Cooperation and Development (OECD) that is a significant net hydrocarbon exporter, exporting about two-thirds of its total energy production. Australia was the world’s largest coal exporter and the fourth largest exporter of liquefied natural gas (LNG) in 2009, after Qatar, Malaysia, and Indonesia. Australia’s prospects for expanding these energy exports in the future are promising as Asian demand for both coal and LNG is rising along with Australia's proven natural gas reserves. While Australia also exports crude oil and refined petroleum products, it is a net importer of oil. Hydrocarbon exports accounted for 19 percent of total export revenues in 2009.

Australia's stable political environment, substantial hydrocarbon reserves, and proximity to Asian markets make it an attractive place for foreign investment.


According to The Oil and Gas Journal(OGJ), Australia had 3.3 billion barrels of proven oil reserves as of January 1, 2010, more than double the 2009 OGJ estimate of 1.5 billion barrels. Increases in reserve estimates are reportedly based on additional oil liquids reserves, mainly natural gas liquids and other liquids, discovered through the ongoing drilling taking place in already producing oil and natural gas basins. The majority of these reserves are located off the coasts of Western Australia, Victoria, and the Northern Territory.

Australia Oil Production and Consumption 1990 2010

Sector Organization

Australia’s management of oil exploration and production is divided between the state and Commonwealth (Federal) governments. Australia’s state governments manage the applications for onshore exploration and production projects, while the Commonwealth Government shares jurisdiction over Australia’s offshore projects with the government of the adjacent state or Territory. The Ministry of Industry, Tourism and Resources (MITR) and the Ministerial Council of Energy (MCE) both function as regulatory bodies over Australia’s oil sector. In place of a national oil company, the Australian government supports privately held Australian companies, of which the largest are Woodside Petroleum and Santos. ExxonMobil is the largest foreign oil producer; other international oil companies include Shell, Chevron, ConocoPhillips, Japex, Total, BHP Billiton, and Apache.


In 2009, oil production totaled 589,000 barrels per day (bbl/d), of which 81 percent (476,000 bbl/d) was crude oil. Oil production in Australia peaked in 2000 at 828,000 bbl/d and has since been declining. According to the Australian Petroleum Production and Exploration Association (APPEA), a continued decline in oil liquids production is expected over the next decade.

Australia’s main frontier for exploration has moved in recent years to the deepwater area of the Timor Sea, although the nearby Carnarvon Basin off the coast of Western Australia remains the busiest area in terms of overall drilling activity. After a spike in drilling activity in the past decade, several major discoveries are now in the process of being put into commercial operation.

The Pyrenees and Van Gogh projects offshore Western Australia came online in the first quarter of 2010 and are expected to make a significant contribution to oil production. Pyrenees has a production capacity of 96,000 bbl/d and Van Gogh has a production capacity of 150,000 bbl/d. In fiscal year 2010-2011, these projects are expected by the Australian Bureau of Agricultural and Resource Economics (ABARE) to increase oil exports by 7 percent in line with higher production, aided by the Kipper and Turum fields starting up in the beginning of 2011 at 10,000 and 11,000 bbl/d, respectively. These additions to production are expected to offset the fall in output in other fields at least in the short term.

In 2010, 31 new exploration areas in 5 offshore basins were offered for bidding, with closing dates either November 2010 or May 2011, depending on the exploration status and data available in these areas.


Australia has a well-developed domestic oil and gas pipeline network. The Australian Pipeline Trust, with 6,200 miles of pipeline, is the largest operator. Epic Energy is the second largest, with 2,500 miles of pipeline. Santos operates two major domestic pipelines that are used for carrying oil and oil products, which include the Jackson to Brisbane line that spans 500 miles, and the Mereenie to Alice Springsline that covers 167 miles. Esso Australia Ltd. operates the 115-mile Longford to Long Island Point pipeline.

Imports and Exports

In 2009, according to EIA estimates, Australia had net oil imports of about 360,000 bbl/d, close to 40 percent of its domestic consumption of 946,000 bbl/d. The high proportion of imports as a share of total oil production reflects the location of the majority of Australia's oil production off its northwest coast, which is closer to Asian refineries than to Australia's domestic refineries, located on its east coast. Conversely, the majority of Australia's refinery capacity is located close to its major domestic consuming markets on the east coast.Australia's crude oil and condensate imports mainly come from South East Asia; Viet Nam is currently the largest source, while Singaporeis the largest source for Australia's refined product imports.

According to EIA estimates, in 2008, Australia had gross exports of 249,000 bbl/d of crude oil, about 42 percent of its total oil production, going to Asian markets, mainly South Korea, Singapore, and Taiwan. Australia's 2008 gross exports of petroleum products were 62,800 bbl/d, about 11 percent of its total oil production; its largest markets were New Zealand and Singapore.


According to The Oil and Gas Journal, in January 2010, Australia had 7 major refineries, with a total crude oil refining capacity of 725,000 bbl/d, up from 696,000 bbl/d in 2008. Crude oil feedstock for these refineries primarily comes from oil produced in the Bass Strait offshore southeastern Australia as well as imports.

Natural Gas

According to The Oil and Gas Journal (OGJ),Australia had 110 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2010, triple OGJ's 2009 reserves estimate of 30 Tcf. The upgrade is largely a result of increased exploration and development of its unconventional as well as conventional gas sources. It has been reported that unconventional gas deposits, i.e., coal seam and shale gas deposits, have become an increasingly larger component of gas reserves due to technological advances. Australia was the twelfth largest holder of natural gas reserves in the world in January 2010. However, significant new discoveries have been announced as recently as July and August 2010.

Sector Organization

The Australian government has no ownership stake in the domestic natural gas industry. The industry is regulated by the Ministry of Industry, Tourism and Resources (MITR) and the Ministerial Council of Energy (MCE). The Australian government created the MCE in 2001 in order to build policy coordination between the Commonwealth Government and the state governments. The MCE functions as the director of natural gas policy. Major domestic and foreign players operating in Australia include Santos, Woodside, Chevron, ConocoPhillips, ExxonMobil, Origin Energy, BG Group, Apache, INPEX, Total, and Shell.


Natural gas production in Australia reached 1.5 Tcf in 2009 and is on a rising trend, with significant new projects coming onstream in the short to medium term. Queensland and New South Wales are the main sources for coal seam gas (CSG), which accounted for 13 percent of gas production in 2009, while conventional gas is largely located in the Carnarvon Basin offshore North Western Australia. Much of Australia's natural gas production is converted into LNG for export as well as for domestic consumption. A number of major new LNG projects are under construction or planning as the Asian LNG market continues to expand; 4 projects will use conventional gas from offshore the northwest coast and 4 will be based on LNG extraction from CSG in Queensland.

Australia Natural Gas Production consumption 1990 2010

Conventional new LNG production projects include:

The Pluto project is under construction near Karratha offshore Western Australia. Woodside Energy owns 90 percent of the venture supported by 15-year contracts with Kansai Electric and Tokyo Gas at 5 percent equity each. The project includes an offshore platform connecting 5 subsea wells and a 112-mile pipeline to an onshore LNG facility on the Burrup Peninsula. The first train is expected to come online in March 2011 with estimated new capacity of 200 billion cubic feet (Bcf) of LNG per year.

The Gorgon project, led by Chevron (50%), with Shell and ExxonMobil (25% each), is currently under construction. The Gorgon gas field, which is 80-124 miles off the northwest coast, is believed to contain 40 Tcf of natural gas and is currently Australia's largest known natural gas resource. The project includes development of the Gorgon gas fields with subsea pipelines to Barrow Island; a gas processing facility on the island with production capacity of 700 bcf per year, consisting initially of three, 234 Bcf per year LNG trains; LNG shipping facilities to transport products to international markets; and greenhouse gas management via injection of carbon dioxide into deep formations beneath Barrow Island. It was reported that both the Western Australia Environmental Protection Authority and the Australian Environmental Ministry approved the project in August 2009. A final Investment Decision was made on September 14, 2009 and the project is expected to be completed in 2014.

The Icthys project, still in the planning stages, is led by Japan's INPEX (74%) and Total (26%), is also located offshore the northwest coast in the Browse Basin. It is expected to produce LNG, LPG, and condensate for export to Japan and elsewhere via a 528-mile undersea pipeline connecting the fields to a new export LNG terminal to be built near Darwin. When the project comes onstream in 2016 its production is expected to be at least 377 Bcf per year.

The Wheatstone project, still in the planning stages, is led by Chevron (75%) and Apache (25 %) and is supported by LNG contracts with Tepco and Kogas. When complete, its LNG export plant's capacity will reportedly be 1,177 Bcf per year and there will be a smaller plant for domestic production. Final investment decision is due in 2011, but the project has already attracted third party gas as local subsidiaries of Apache and KUFPEC have signed deals to join the project as gas suppliers from their nearby Julimar and Brunello fields and 25 percent equity participants, which will extend the life of the project.

Unconventional new LNG production projects still in the planning stages include:

The Gladstone project will be the world's first major CSG to LNG operation. Located onshore Queensland, this project is currently a joint venture between Santos (60%) and Petronas (40%), although discussions with Shell to take a one-third equity share are reportedly ongoing. The project received environmental approval from the Queensland government in May 2010. Gladstone LNG has plans for 2 plants with capacity of 175 Bcf each. Sinopec and Korea Gas Corp. are expected to buy small stakes in the project.

Arrow CSG to LNG project is another Queensland-based venture in the planning stages. A joint venture between Shell and PetroChina is reportedly in the process of acquiring Arrow. The Arrow project involves building up to 4 LNG processing plants, each with a capacity of 195 Bcf per year. A recent statement by Santos about collaboration between projects has fueled speculation that a deal between Santosand Shell could be followed by a merger of Gladstone and rival Arrow to save on infrastructure and equipment costs.

Analysts expect a merger may also occur between 2 other rival projects in Queensland: one is the Australia Pacific project, a 50-50 joint venture between Origin and ConocoPhillips, and the other is the Queensland Curtis project being developed by BG Group and China's CNOOC.

LNG Exports

The distances between Australia and its key natural gas export markets in Asia discourage any pipeline trade; all exports are in the form of LNG. Over the past decade, Australian LNG exports have increased by 48 percent and they are expected to continue to increase over the short to medium term. According to Cedigaz, in 2009, Australia exported 856 Bcf of LNG, up from the 755 Bcf reported by EIA in 2008. Japan is the primary destination, but other purchasers include China, South Korea, India, and Taiwan.

Australia Lng Export

Australia currently has 2 LNG export facilities. The largest is the North West Shelf Venture (NWSV), a consortium of 6 energy companies (Woodside, Shell, BP, Chevron, Japan Australia LNG, BHP Billiton), which operates 5 offshore LNG trains with a total capacity of 761 Bcf per year. It relies on natural gas supplied from nearby fields in the Northwest Shelf (NWS). The majority of LNG produced by the NWSV is exported to Japan by long-term contracts. Darwin LNG is the second facility, a consortium of ConocoPhillips, Santos, Eni, SPA, and INPEX. It has 1 production train with a total capacity of 140 Bcf per year and exports LNG under contracts to Tokyo Gas Corp. and Tokyo Electric. Darwin is located on Australia’s northern coast and is supplied with natural gas from fields in the Timor Sea. However, as the new LNG facilities come online beginning with the Pluto project, Australia's LNG export capacity will be expanding substantially.


As of the beginning of 2009, Australia contained 76 billion short tons (Bst) of recoverable coal reserves. Australia is the world's fourth largest coal producer, after China, the United States, and India, but it is the largest exporter.

Sector Organization

Australia has around 107 privately owned coal mines located throughout the country. About 74 percent of Australia's coal production comes from open pit operations, with the remainder coming from underground mines. International companies such as BHP Billiton, Anglo American (UK), Rio Tinto (Australia-UK), and Xstrata (Switzerland) play a significant role in Australia's coal industry.


In 2009, Australia produced 450 million short tons (MMst) of coal. Over the last 2 decades, coal production in Australia has grown by 34 percent, with new projects continuing to come online every year. The states of Queensland and New South Wales (NSW) together account for 97 percent of Australia's black coal production. Black coal production has been increasing by an average of 3.2 percent per year between fiscal years 2003-04 and 2008-09, supported by the addition of new capacity, and is expected to continue to increase over the medium term. Australia also has brown coal deposits in South and Western Australia, Victoria, and Tasmania, where it is used for domestic electricity generation.

Australia Coal Production Consumption 1990 2010


Australia exported about 66 percent of its coal production in 2009, or about 300 MMst, accounting for 28 percent of global coal exports. According to the Australian Coal Association, Japan was the destination for over 40 percent of Australia’s coal exports during Australian fiscal year 2008-2009. Other important export markets included South Korea (15%), Taiwan (10%), and India and China (9.5% each). About 8 percent of Australia's coal exports went to Europe.

The export coal industry is serviced by 9 coal loading terminals located in Queensland and NSW. These terminals in June 2009 had handling capacity of 364 cubic feet per year. Several new port infrastructure projects are in various stages of development and are expected to add about 130 million short tons to annual coal export capacity by 2014.

Japan Fuel Consumption shows recovery after tsunami

Earthquakes usually exact a limited toll on the global economy. The earthquake and tsunami that struck Japan in March 2011 was different, however, as energy markets across the globe felt the impact. Japan is a large player in world energy markets, including petroleum. The disaster occurred when Japan's liquid consumption was starting its seasonal decline. While most of the apparent liquids consumption decline that eventually occurred was seasonal, the earthquake and the tsunami exacted their toll as well: Japan's consumption level in May 2011 dropped to the lowest monthly level since recordkeeping began in 1984. However, as Japan's recovery has progressed, the direction of the disaster's impact on the nation's petroleum use has reversed. With only 10 of 54 nuclear reactors currently operating, liquid fuels and natural gas used for power generation increased to make up for the lost nuclear generation. According to the International Energy Agency's (IEA) Monthly Oil Data Service, Japan's average daily liquid fuels consumption in July and August was higher than last year.

Despite having few domestic energy resources, Japan plays a vital role in many global energy markets. It is the world's fourth largest energy consumer, and prior to the earthquake, the third largest producer of nuclear power. The country is one of the top five natural gas consuming nations and the world's largest importer of liquefied natural gas (LNG) and coal. Japan is also the world's third largest liquid fuels consuming economy, surpassed only by the United States and China, which requires it to be the world's third largest importer of crude oil.

Japan's nuclear power generation infrastructure sustained significant damage, mostly as a result of the tsunami. More significantly, undamaged nuclear reactors that were taken offline following the Fukushima incident accounted for the majority of the nuclear capacity that was shut down, leading to an increased demand for fossil fuels to meet base-load power generation needs. According to the latest information provided by the Japan Atomic Energy Agency, the shutdown capacity totals 40,276 megawatts (MW), while the 10 units currently operating account for about 8,684 MW of nuclear capacity. Other fuels were used to replace the lost nuclear generating capacity. This was mostly in the form of natural gas but also liquid fuels; some estimates reported increases as high as 200 thousand barrels per day (bbl/d). The Federation of Electric Power Companies of Japan reported that LNG consumption by power producers rose nearly 31 percent by June year-over-year, and by 23 percent by July. In fact, Japan's July LNG imports rose to a five-year high of 7.1 million tons, according to Deutsche Bank.

Petroleum infrastructure, including refineries, factories, ports, roads, and other transport logistics that directly affect the use and movement of crude oil and liquid fuels also sustained significant damage. In the tsunami's aftermath, six oil refineries with a total capacity of 1.4 million bbl/d (about 30 percent of Japan's total refining capacity) were shut down or had limited operations for a period of time. Since then, the majority of refineries have returned to pre-tsunami levels, with the only notable exception being the 145 thousand bbl/d Sendai refinery, which remains out of service.

Japan's oil consumption decreased following the earthquake and tsunami (Figure 1). Total consumption of liquid fuels dipped to 4.6 million bbl/d in March, about 10 percent lower than the previous month, and about 3 percent lower than total consumption for the same month during 2010. Liquid fuels consumption continued to decrease in both April and May, with the May level about 1 million bbl/d lower than consumption in the February preceding the disaster, which is a typical seasonal decline. However, the subsequent growth of about 666,000 bbl/d from May through August was substantially higher than the typical seasonal increase. With Japan's recovery well underway, consumption is expected to remain strong. According to the U.S. Energy Information Administration's Short-Term Energy Outlook, Japan's liquids fuel consumption may increase by about 1 percent in 2011 over 2010.

Japan Fuel Consumption Recovery 2011

Related Topics:
Impact of Japan Earthquake on Oil Consumption.
Japan Energy Report

Friday, October 14, 2011

The Northeast Home Heating Oil Reserve cut in half

The Northeast Home Heating Oil Reserve (NHHOR) will be reduced to one million barrels, half its original size, as the stockpile's holdings are converted to ultra-low-sulfur distillate (ULSD) fuel that will be stored only in New England States. The Department of Energy (DOE) chose to end leasing storage space for the reserve in New York harbor because that area is well supplied with commercial ULSD inventories. There are also several nearby refineries and a major pipeline that could quickly provide heating fuel this winter.

The reserve is switching to ULSD because several Northeast States will require the use of very low-sulfur fuel within the next few years. New York has already approved a reduction in the maximum sulfur content of heating oil from the current 2,000 parts per million (ppm) to 15 ppm by July 2012. New Jersey, Pennsylvania, Maine, Connecticut, and Rhode Island have legislation pending.

DOE awarded contracts to Hess Corporation to store 500,000 barrels of ULSD at the company's terminal in Groton, Connecticut and to Global Companies LLC to store 500,000 barrels in Revere, Massachusetts. DOE plans to sign contracts later this month for purchasing the one million barrels of ULSD that now will be delivered to the reserve by the end of November.

NHHOR was authorized in 2000 to provide the region with two million barrels of backup heating oil in case of a disruption in winter heating fuel supplies. The Northeast is the biggest heating oil market in the world, where 69% of U.S. households that use heating oil are located.

DOE earlier this year sold the two million barrels of heating oil in the reserve and decided to replace it with one million barrels of ULSD that will be stored at locations in New England to protect six States—Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont—that are most vulnerable to supply problems.

Total distillate fuel inventories for the central Atlantic region—Delaware, Maryland, New Jersey, New York, Pennsylvania, and the District of Columbia—were 35.4 million barrels at the end of September, down 19.4% from a year earlier. Similar distillate inventories for New England were much smaller at 12.2 million barrels, down 12% from a year ago.

U.S. Oil Inventories

Connecticut Heating Oil Reserve
Of the 7.7 million households in the United States that use heating oil to heat their homes, 5.3 million households, or nearly 70 percent, reside in the Northeast region of the country - making this area especially vulnerable to fuel oil disruptions.

Creation of an emergency reserve of heating oil was directed by President Clinton on July 10, 2000, when the President directed Energy Secretary Bill Richardson to establish a two million barrel home heating oil component of the Strategic Petroleum Reserve in the Northeast. The intent was to create a buffer large enough to allow commercial companies to compensate for interruptions in supply during severe winter weather, but not so large as to dissuade suppliers from responding to increasing prices as a sign that more supply is needed.

Two million barrels would give Northeast consumers supplemental supplies for approximately 10 days, the time required for ships to carry additional heating oil from the Gulf of Mexico to New York Harbor.

Immediately after the President's July 10, 2000, directive, the Energy Department, acting through the Defense Energy Support Center, issued a solicitation to exchange crude oil from the Strategic Petroleum Reserve for two million barrels of distillate heating oil stocks to place in leased storage facilities in the Northeast.

heating oil reserve perth amboy newjersey

An exchange using Strategic Petroleum Reserve crude oil was chosen because no appropriated funding was available to create the heating oil reserve.On July 19, 2000, the Defense Energy Support Center issued a solicitation to companies willing to provide the storage tanks, heating stocks, or a combination.

By October 13, 2000, all of the heating oil had been delivered. In November 2000, Congress amended the Energy Policy and Conservation Act of 2000 providing clear authority for the reserve.As Americans confronted the winter of 2000-2001, the Northeast Home Heating Oil Reserve was deemed ready.
The Bush Administration Endorses the Reserve
Although heating oil shortages did not materialize during the 2000-2001 winter, the existence of the Northeast Home Heating Oil Reserve provided an important safety cushion for millions of Americans.

Recognizing this, the incoming administration of George W. Bush reinforced the value of the Reserve. On March 6, 2001, Energy Secretary Spencer Abraham formally notified Congress that the Bush Administration would establish the Reserve as a permanent part of America's energy readiness effort, separate from the Strategic Petroleum Reserve.

In May 2001, President Bush issued his National Energy Policy which again endorsed the Reserve as a way to help ensure adequate supplies of heating oil in the event of colder than normal winters.
The Home Heating Oil Reserve Today

February 2011 Sale. On February 1, 2011, DOE announced its plan to convert the 1,984,253-barrel inventory of the Reserve to cleaner burning ultra-low sulfur distillate. DOE’s plan corresponds with recent actions by the State of New York and other Northeastern states that are implementing more stringent fuel standards that require replacement of high sulfur heating oil to the cleaner burning distillate.

On February 3, 2011, DOE conducted a competitive on-line sale for the new initiative, offering approximately 1,000,000 barrels of heating oil from the Hess First Reserve Terminal in Perth Amboy, NJ. Contracts were awarded to three companies for 984,253 barrels. Receipts from the sale total approximately $113 million.

On February 10, 2011, DOE conducted a second on-line sale, offering 1,000,000 barrels of heating oil from terminals located in Groton and New Haven, CT. The sale resulted in awards to four companies for the full amount offered. Recipts total approximately $114 million.

Successful execution of the sale of the Northeast Home Heating Oil stocks has completed the first part of the DOE initiative to convert the Reserve. DOE plans to use the receipts for purchase of ultra low sulfur heating oil prior to the 2011-2012 heating oil season.

Reestablishing the NEHHOR. On March 14, 2011, a solicitation was issued by the Defense Logistics Agency (DLA Energy) on behalf of DOE for new storage contracts for the Northeast Home Heating Oil Reserve. On August 18, 2011, DOE announced that new contracts were awarded to two companies for storage of 650,000 barrels of ultra low sulfur distillate in New England. Hess Corporation in Groton, CT will store 400,000 barrels, and Global Companies LLC in Revere, MA will store 250,000 barrels. A solicitation for storage of an additional 350,000 barrels will be issued in order to establish a one million barrrel Heating Oil Reserve prior to the 2011-2012 winter heating season.

Establishment of a one million barrel Reserve will provide supplemental supplies to the area most vulnerable to a supply disruption, New England. DOE announced that it would not reestablish a Heating Oil Reserve facility in New York Harbor because the area has abundant commercial stocks and connections to local refineries and a major pipeline for resupply.

Ultra low sulfur distillate will be purchased and delivered to the Northeast Home Heating Oil Reserve storage facilities before the heating season begins.

Thursday, October 13, 2011

Oil Discovery at Western Desert, Egypt

Kuwait Energy Company KSCC (“Kuwait Energy”), announced it has encountered hydrocarbons in the GPZZ-4 and Al Ahmadi-1 wells located in the Abu Sennan concession in the Western Desert, Egypt.

The Abu Sennan concession is operated by Kuwait Energy in which it holds a 50% working interest with the remainder being held by Beach Energy Limited (22% working interest) and Dover Petroleum (28% working interest). These two new discoveries bring the total number of discoveries since 2008 by Kuwait Energy in Egypt to 13.

Kuwait Energy Deputy Chairman and CEO, Sara Akbar said: “We have registered yet another success in Egypt with these discoveries. Production testing on both wells is still ongoing to assess the volumes and commerciality of the hydrocarbon shows. We look forward to encouraging results, as well as continued success in Egypt.”

Al Ahmadi-1 (Beach 22%) is the second discovery on the Abu Sennan permit having encountered shows in the lower Baharya Formation, the Abu Roash ‘G’ Member and the Abu Roash ‘E’ Member. GPZZ-4 was drilled as the first well of a six-well program in the Abu Sennan concession. During initial testing, gas and condensate flows were recorded from the lower Bahariya Formation. These tests recorded gross flow rates of approximately 850 barrels (bbls) of condensate and seven million standard cubic feet (MMscf) of gas per day. This equates to a gross equivalent flow rate of approximately 2,000 barrels of oil equivalent (boe) per day. GPZZ-4 also recorded flows from the Abu Roash "G" Member and the upper Bahariya Formation with initial rates of approximately 150 bbls of condensate and 1.6 MMscf of gas per day.

The second well, Al Ahmadi-1, also recorded gas and condensate flows within the Abu Roash "G" Member. Initial tests recorded gross flow rates of approximately 800 bbls of condensate and 13.5 MMscf of gas per day. This equates to a gross equivalent flow rate of approximately 2,900 boe per day. Al Ahmadi-1 also recorded flows from the lower Bahariya Formation with initial rates of approximately 70 bbls of condensate and one MMscf of gas per day.

Wednesday, October 12, 2011

UK Oil & Gas Economic Report

Oil & Gas UK’s 2011 Economic Report, published today (11 October), confirms the continuing significance of the oil and gas sector to the UK economy and highlights the increasingly important role of the country’s world-class oil and gas supply chain in fostering engineering, manufacturing and technology excellence as well as enabling production of the UK’s oil and gas resource.

The sector is one of UK industry’s stalwarts, continuing to support hundreds of thousands of highly skilled, well-paid jobs and meeting the majority of the nation’s energy needs. It provides a major boost to the public finances, helping the country combat the pressures imposed by the current global economic situation.

The report shows that over 40 billion barrels of oil and gas equivalent (boe) have already been extracted from the UK continental shelf (UKCS) as a result of £468 billion (2010 prices) of capital and operating investment over the past 40 years. The country remains a globally significant producer of oil and gas, with an average 2.2 million barrels of oil and gas equivalent (boe) per day produced in 2010. This production satisfied around 90 per cent of the country’s oil demand, 60 per cent of our gas demand and represents well over half of our primary energy needs. With a value of £32 billion, it reduced our requirement for imported oil and gas to the extent that the UK’s trade deficit was almost halved.

£14 billion was spent on exploration, development and operations in 2010. This included £6 billion of investment in new projects, an increase of a fifth on 2009, making the oil and gas industry again the largest investor among the UK’s industrial sectors. Also essential in the production equation is the application of the high-class skills and technology developed within the supply chain, ranging from reservoir and subsea engineering to well services, facilities engineering and support services.

Projected UKCS Reserves

Malcolm Webb, Oil & Gas UK’s chief executive, said: “The industry’s world-class oil and gas supply chain that has grown up alongside forty years of production is perfectly placed to continue to foster excellence in engineering, manufacturing and technology in the UK, just the sort of economic activity the nation needs to succeed in re-balancing the economy. Our Economic Report shows how the UK fabrication and well services sectors in particular are flourishing.

“What’s more, the development of the UK’s offshore oil and gas gave the supply chain here a ‘first mover’ advantage in seeking out and building global markets for its oilfield goods and services. Such products and expertise are now in increasing demand and, in 2010, international sales by the supply chain were estimated at £6 billion.”

Uk New Wells Started

The positive impacts of investment and production activity are wide-ranging. Employment of 440,000 people is currently supported by the industry with 340,000 of these related to finding, developing and producing our own reserves and another 100,000 occupied with supplying goods and services to oil and gas provinces around the world. Far from being based purely in traditional oil and gas centres, they are spread across the country. While 45 per cent of employees are in Scotland, one fifth live in south east England, over ten per cent live in north-east and north-west England and five per cent live in the east of England.

UK Production Forecast

The wider population also benefits from this employment as income tax revenues and national insurance contributions flow directly to the public purse; together with corporation tax paid by supply chain companies, this is estimated at £6 billion a year. But this is more than matched by the tax paid on production itself, £8.8 billion in 2010-11, which constituted one fifth of total corporation tax received by the Exchequer. The proportion paid by the oil and gas industry on production is forecast by the Treasury to increase further in 2011-12 to over £13 billion, or just over a quarter of the expected total corporation tax.

Mr Webb continued: “For decades to come, it is clear that on practical, technical and cost grounds the UK will still require oil and gas to provide the bulk of its energy. Making full use of our own significant remaining oil and gas resource – estimated to be up to 24 billion barrels – will ensure the sector continues to contribute to the UK economy in the years ahead and strengthen the country’s manufacturing and engineering base through the industry’s technology driven, high value-adding, world class supply chain.

Future Hourly Electricity prices

“Forecasts prepared at the start of 2011 showed that investment to develop UK oil and gas was set to increase dramatically to £8 billion in 2011 and be sustained at that rate for the next five years. If the investment planned then was realised, over 40 per cent of our primary energy demand or 60 per cent of oil and gas demand could still be satisfied from these resources in 2020.”

However, the current business environment does raise concerns about the competitiveness of the UKCS and hence the sector’s ability to attract the investment required to extract the full 24 billion resource. The confidence of the industry was severely shaken by the Budget of March 2011 with the surprise announcement that the tax rate would increase to a new top rate of 81 per cent, while access to tax relief on decommissioning costs would be capped at old tax rates. The value of projects was reduced by almost a quarter overnight and the positive effect of new field allowances that had specifically been put in place by the Treasury to encourage investment in technically challenging, small or remote fields was significantly eroded.

UK Oil Gas Employment

Mr Webb said: “The average size for new discoveries is small at around 20 million barrels, yet development costs are high. A heavy tax rate, especially for projects involving additional investment in mature fields, and greater uncertainty over future tax treatment, has not helped the industry’s case in proving attractive to international investors. Transfer and trading of equity in older assets has also slowed to a trickle.

“Developments where investment is already committed or where the reserves are material and the economics sufficiently robust to withstand the tax increase, will go ahead. However, for those making investment decisions on economically marginal projects in the medium and longer term, the UK will now appear lower down the international rankings as a destination for their capital. What we now see is something of a ‘two speed UKCS’ whereas what is really needed for the economy and energy security is every effort to push along investment in all technically viable projects. As a result, Oil & Gas UK is working closely with the Government to find a way to stimulate investment in developments which are now ‘fiscally stranded’. We believe that the current field allowance structure will need to be extended or modified to sustain investment in existing and new fields, especially the more difficult or marginal ones.”

Platforms Constructed Each Year UK

Mr Webb concluded: “Oil & Gas UK has been working alongside Treasury officials to find ways to stimulate investment in existing fields and to develop proposals to resolve the current uncertainty over access to decommissioning tax relief. We have been encouraged by the constructive engagement of the Treasury, Ministers and officials in both projects and we hope to identify a much-needed solution by the Budget of 2012.

“I firmly believe that this is an industry that can continue to make a major contribution to the UK economy and UK security of energy supply for decades to come. Our globally recognised expertise in oil and gas related technology, engineering, manufacturing and services provides a fantastic platform for the future – both domestically and in overseas markets. In these difficult economic times, we must nurture this jewel in the UK economic crown.”


Key figures (2010 unless otherwise stated) from the 2011 Economic Report:
  • Production from the UK’s continental shelf (UKCS) satisfied 55% of the country’s primary energy demand (87% of oil and 61% of gas).
  • Production of UK oil and gas boosted the balance of payments by £32 billion and the supply chain added another £5-6 billion in exports of oilfield goods and services.
  • Production was 810 million boe, or an average of 2.2 million boe per day, a decrease of about 6.5% from 2009. In worldwide terms, the UK is the 15th largest gas producer (3rd in Europe) and 20th largest oil producer (2nd in Europe).
  • The “effective UKCS output” price was $63 per barrel of oil equivalent (boe), derived from annual oil and gas prices pro rata to production.
  • Total expenditure reached £14 billion on exploration, developments and operations.
  • The industry paid £8.8 billion on production in the tax year 2010-11, which is 20% of total corporation taxes received by the Exchequer. This is expected to rise to over £13 billion in 2011-12, providing over one quarter of total corporation taxes. The wider supply chain is estimated to have contributed another £6 billion in corporate and payroll taxes.
  • Unit operating costs rose slightly to $12.5/boe; this trend is forecast to continue with unit costs rising to nearer $14/boe in 2011.
  • Just over 40 billion boe have so far been recovered from the UKCS and the remaining resource is forecast to be up to 24 billion boe.
  • The industry supported about 440,000 jobs across the UK.
More info: United Kingdom Energy Report

Tuesday, October 11, 2011

The Oil and Gas Sector Revenue Sharing

Oil and gas extraction plays a dominant role as a source of export earnings and, to a lesser extent, employment in many developing countries. But the most important benefit for a country from development of the oil and gas sector is likely to be its fiscal role in generating tax and other revenue for the government. To ensure that the state as resource-owner receives an appropriate share of the economic rent generated from extraction of oil and gas, the fiscal regime must be appropriately designed.

The government, as resource owner, has a valuable asset in the ground. This asset—a crude oil or natural gas deposit—can only be exploited once. In order to convert this asset into financial resources, the government must attract capital on terms that ensure it gets the greatest possible value for its resources—under uncertainty about what the value of the resources will turn out to be.

There is a fundamental conflict between oil and gas companies and the government over the division of risk and reward from a petroleum project. Both want to maximize rewards and shift as much risk as possible to the other party. Nevertheless, the right choice of fiscal regime can improve the trade-off between each party’s interests—a small sacrifice from one side may be a big gain for the other. Oil and gas agreements and the associated fiscal rules establish the “price” of the resource in terms of the bonuses, royalties, taxes or other payments the investor will make to the government over the life of the project. Designing fiscal arrangements that encourage a stable fiscal environment and efficient resource development maximizes the magnitude of the revenues to be divided.

In designing fiscal instruments, the government will need to weigh its desire to maximize short-term revenue against any deterrent effects this may have on investment. This will require a balanced sharing of risk and reward between the investor and the government. The aim should be for fair and rising government share of the resource rent, without scaring off potential investors.


The government can collect revenue from the oil and gas sector by a variety of tax and nontax instruments. Most countries collect the government share of economic rent primarily through production-based or profit-based instruments. In some countries, the government participates more directly in project by taking an equity interest.

Policymakers will also have to decide on the treatment of indirect taxes such as VAT and customs duties. Multiple fiscal instruments may be needed to create an identity of interest between the government and the oil and gas companies over the life of the agreement. Production-based instruments, such as royalties, can ensure the government receives at least a minimum payment for its mineral resources. Profit-based instruments allow the government to share in the upside of highly profitable projects, but they also increase the government’s share in the project’s risk inasmuch as the government may receive no revenue if the project turns out to be unprofitable.

In addition to product-based and profit-based instruments, there may be bonuses and rental payments of various types. Bonuses can ensure some up-front revenue for the government and may encourage companies to explore and develop contract areas more rapidly. They are usually suitable only in highly prospective areas where there is strong competition among investors for petroleum rights. Annual rental payments typically are not a significant source of revenue but can be designed to encourage companies to explore and develop contract areas or to relinquish their rights.

In many countries with petroleum resources, revenues from different instruments accrue to different parties; for example, royalty payments may be made to local units of government, landowners or the petroleum ministry.

A. Tax/Royalty Regimes

A common way of taxing the oil and gas sector involves a combination of tax and royalty payments. A tax/royalty regime may involve three levies: (1) a royalty to secure a minimum payment, (2) the regular income tax that is applicable to all companies, and (3) a resource rent tax to capture a larger share of the profits of the most profitable projects.


Royalties are attractive to the government, as the revenue is received as soon as production commences and they are easier to administer than many other fiscal instruments, at least for simple royalty regimes. Furthermore, they ensure that companies make a minimum payment for the minerals they extract. Royalties are typically either specific levies (based on the volume of oil and gas extracted) or ad valorem levies (based on the value of oil and gas extracted). Some countries have introduced a profit element in royalties by having them depend on the level of production (e.g., Chile, Ecuador, Norway, and Thailand) or on a measure of nominal return such as the R factor (e.g., Peru, and Kazakhstan).

As royalties raise the marginal cost of extracting oil, they can deter investors if imposed at too high a level. They may also discourage development of any marginal reserves that have been discovered and lead to early abandonment of productive oil and gas wells. Investors are resistant to the use of royalties, even on potentially rich deposits, partly on the grounds that royalty payments are only a deductible expense in determining taxable income in the home country and are not allowed as a foreign tax credit against the home country’s income tax.

A key issue for policymakers is to determine an appropriate method for the valuation of the extracted oil and gas used as a base for royalties and other taxes. Ad valorem royalties are generally levied on the sales price or the f.o.b. export price, at times after netting back certain costs.

An overriding concern should be the use of an observable price. When using a generally quoted market price (e.g. North Sea Oil), it should be adjusted to reflect differences in gas and crude oil quality and the wellhead value should be established by netting back transportation and other costs.

Income Tax

The income tax should be levied on oil and gas companies, as on all other companies. It is not unusual for the profit tax rate for oil companies to be higher than the general rate for other companies. This is one way to capture a share of the resource rents from the project. Many countries provide an incentive for exploration and project development by allowing exploration costs to be recovered immediately and allowing accelerated recovery of development costs, for example, over five years. Accelerated cost recovery brings forward payback for the investor and, possibly, retirement of debt. It can therefore reduce both The R factor equals cumulative revenues, net of royalties, divided by cumulative costs.

Some countries (e.g. OPEC countries until 1974 and Nigeria until 1986) have historically used governmentset prices, which were often independent from market prices. This practice is disappearing. In contrast, Norway introduced in 1974 a government-set price for oil defined as the real market price of the same type of crude over a given period.

Governments can exercise a considerable amount of discretion in determining price adjustments. For instance, in order to establish gross revenue at the wellhead, the UK inland revenue allowed as deductions from the landed price not only transport costs from North Sea fields but also around 70 percent of production platform costs. This practice was abandoned by the end of the 1970s (Kemp, 1987) investor risk and tax-deductible interest costs; it also facilitates project financing. Some countries offer special incentives to encourage exploration in particular regions.

To protect the tax base, countries may place limits on the use of debt financing to limit “earning stripping” through the payment of interest abroad. To limit abusive transfer pricing between related companies, the tax authority should have the power to adjust income and expenses where under- or overpricing between related companies has resulted in a lowering of taxable profit (see Transfer Pricing).

Transfer Pricing

Through transfer pricing, a taxpayer seeks to minimize income and maximize deductible expenditures in hightax jurisdictions and vice versa in low-tax jurisdictions.

A transfer pricing mechanism that could affect revenue in the oil and gas sector is:

• The creative use by firms of price hedging mechanisms perhaps involving transactions between related parties, causing great difficulty in assessing whether hedging instruments are used for transfer pricing purposes rather than to reduce risk.

More common measures to maximize expenditure deductions include:

• The provision by related parties of highly leveraged debt finance at above-market interest rates.

• Claiming excessive management fees, deductions for headquarter costs, or consultancy charges paid to related parties.

• The provision of capital goods and machinery in leasing arrangements at above-market costs charged by a related-party lessor.

• If the petroleum tax rate is above the standard tax rate, there may be an incentive to establish a domestic shell firm that will on-lend financing capital from related parties to the oil company giving rise to an interest deduction at a higher tax rate than is charged on the interest earnings in the shell company.

Abusive transfer pricing can be very difficult to detect and prevent. Properly designing the tax code, though, is an important first step. At a minimum, the tax legislation should include safeguards requiring that transactions between related parties be assessed on an arms-length basis, or perhaps that certain deductions be capped as a share of total costs. Some countries also impose a limit on the allowable (for tax purposes) debt-leverage of a project. It is also advisable to seek close cooperation with the tax authorities in the home countries of the more important investors.

A related issue for the taxpayer is the treatment of tax credits. Many multinational companies expect to be subject to an income tax in the producing country, as this tax will be creditable against the income tax levied in the home country. Absent an income tax in the producing country, the multinational may be subject to higher tax payments in the home country.

For instance, in Norway, liberal rules (the current limit on external financing is 80 percent) for the deduction of financial costs from both the corporate income tax and the Special Tax has been identified as one of the basic problems of the Norwegian petroleum taxation .Whether or not a tax is creditable depends on the particular tax law in the home country and on any tax treaties in place.

However, a tax paid in the producing country that in nature resembles a home country tax is most likely to qualify for a tax credit. Some specialized mineral taxes, such as a resource rent tax, may be deemed to differ in nature from a standard corporate tax and, therefore, could face difficulties in qualifying for a tax credit. It is important to determine the extent of “ring-fencing” of tax accounts. Ring fencing means a limitation on consolidation of income and deductions for tax purposes across different activities, or different projects, undertaken by the same taxpayer. Some countries ring-fence oil and gas activities, others ring-fence individual contract areas or projects. This can become complex if a project incorporates extraction, processing and transportation activities. If the oil and gas tax regime is more onerous than the standard tax regime, the taxpayer could seek to have certain project-related activities treated as down-stream activities outside the ring fence. If they are treated as a separate activity, the taxpayer through transfer pricing may attempt to shift profits to the lightly taxed downstream activities.

Ring-fencing rules matter for two main reasons:

• Absence of ring fencing can postpone government tax revenue because a company that undertakes a series of projects will be able to deduct exploration or development expenditures from each new project against the income of projects that are already generating taxable income.

• As an oil and gas area matures, absence of ring fencing may discriminate against new entrants that have no income against which to deduct exploration or development expenditures.

Despite these points a very restrictive ring-fence is not necessarily in the government’s interest. More exploration and development activities may occur if taxpayers can obtain a deduction against current income, generating more government revenue over time by increasing the taxable base. The right choice is again a matter of balance within the fiscal regime, the degree of government’s preference for (modest) early revenues over (greater) revenues later on and the extent of the government’s bargaining power with oil and gas companies.

Unless foreign sourced income is exempt in the home country, Oil and gas companies see this provision as a major disincentive. For instance, they have proposed repeatedly that the Indonesian government relax its restriction on transferring expenses from one contract area to another. However, the government maintained its ring-fencing provision (Gao, 1994). Indonesia’s relatively tough fiscal arrangements (Barrows, 1988) are compensated by its attractive oil and gas potential.

Resource Rent Tax

An innovative attempt both to provide the government with an appropriate share of economic rent and to make the tax system less distortive to investors is the resource rent tax (RRT). The RRT (such as is applied for example in Australia and Papua New Guinea) is imposed only if the accumulated cash flow from the project is positive. The net negative cash flow (in the early years of a project) is accumulated at an interest rate that, in theory, is equal to the company’s opportunity cost of capital (adjusted for risk).

The RRT takes a share of returns once the company has earned this hurdle rate of return. If the only tax imposed is the RRT, the government’s revenue stream becomes back-loaded, and for less profitable projects, the government may not receive any revenue at all. Therefore, a resource rent tax is usually combined with royalties and a standard profit tax to provide some early revenue.

Only for very profitable projects will the resource rent tax then apply. Conceptually, a RRT has strong economic features. Properly designed, a RRT captures a share of the natural resource rent, which is the return over and above the company’s opportunity cost of capital. Proponents argue that the RRT can enhance contract stability because it automatically increases the government share in highly profitable projects. For the

RRT to be efficient, each contract area needs to be ring-fenced. That is, costs incurred in one contract area cannot be used to offset the revenues in another contract area. One exception to this rule may be to allow unrecovered costs from an abandoned contract area to carryover to a contract area that remains active. This helps to prevent an RRT from discriminating against exploration.

While the resource rent tax has much theoretical appeal, it has not been a significant revenue raiser in practice. There may be many reasons for this. It could reflect the difficulty of designing the tax, particularly the choice of the discount (or hurdle) rate and tax rate. If the hurdle rate is set too high, chances are that the resource rent tax will never apply; if it is set too low, the tax may become a major deterrent to investment.

If either the hurdle rate of return is too low or the tax rate too high, the RRT will also increase the incentives for oil The “opportunity cost of capital”, which is equal to the discount rate, means the expected return on the best alternative use of available funds.

Palmer recommends that the resource rent tax be combined with a traditional company profits tax.A weakness of a tax based on rates of return is that it does not take geological risks into account companies to engage in tax avoidance, which in countries with a weak tax administration may be very difficult to detect and control.

B. Production Sharing

An alternative to a tax/royalty regime is production sharing.

Under a production sharing arrangement the ownership of the resource remains with the state and the oil and gas company is contracted to extract and develop the resource in return for a share of the production. The government retains the right to petroleum reserves in the ground but appoints the investor as “contractor” to assist the government in developing the resources. Instead of paying the contractor a fee for this service, while the government bears the risk, cost and expense, the parties agree that the contractor will meet the exploration and development costs in return for a share of any production that may result. The contractor will have no right to be paid in the event that discovery and development does not occur. In principle, the government retains and disposes of its own share of petroleum extracted, though joint-marketing arrangements may be made with the contractor The mechanics of production sharing in principle is quite straightforward. The production sharing contract (PSC) will usually specify a portion of total production, which can be retained by the contractor to recover costs (“cost oil”). The remaining oil (including any surplus of cost oil over the amount needed for cost recovery) is termed “profit oil” and is divided between the government and the contractor according to some formula set out in the PSC.

Royalties can also be introduced into the production sharing regime. In some PSCs there is an explicit royalty payment that is paid to the government before the remaining production is split between cost and profit oil. An alternative to a royalty is to have a limit on cost oil (e.g., 60 percent of production), which ensures there is profit oil, as soon as production commences. Where a cap is imposed on the deduction of costs and costs are at this limit, the cap will have a similar economic impact as a royalty, with the government receiving revenue—its share of profit oil—as soon as production commences.

Unrecovered costs in any year are carried forward to subsequent years, but some PSCs allow these costs to be uplifted by an interest factor to compensate for the delay in cost recovery. Interest expense is generally not a recoverable cost. If interest expense is allowed to be recovered, then there should be no uplift for unrecovered costs as this would involve a double counting to the extent unrecovered costs are debt financed.

Although in this respect a properly designed RRT is probably less distortionary than the regular corporateincome tax, since normal CIT postpones the achievement of a desired rate of return (particularly if slow depreciation rates are specified) and therefore encourages other behavior likely to increase current deductions.The split of profit oil is often fixed—60 percent for the government and 40 percent for the investor, for example. It may vary by level of production, the price of crude oil, or the internal rate of return earned on the project. Contractors often pay income tax on their share of production. This tax could be paid out of the government’s share, but then the government’s share should be increased, all other things equal.

A significant advantage of this approach is that the contractors would have fiscal stability—any future changes in the tax rules would affect only the allocation of the government’s share between tax and non-tax oil. The assurance of fiscal stability is an important investment incentive, carrying the cost of reduced flexibility for the government to increase tax on a given project in future (see Fscal Stability Clauses) on explicit fiscal stability clauses).

Fiscal Stability Clauses

Given the nature of investment in oil and gas extraction—long term, large-scale and up-front—a particular concern for investors is to guard themselves against unforeseen changes to the financial premises of the project. One safeguard mechanism that is often sought by investors is the inclusion of a fiscal stability clause in the project agreement. While this to the government can seem an attractive and, in the short run, inexpensive way of minimizing investor risk, it does limit the government’s flexibility to set tax policy, potentially resulting in a revenue loss and increased administrative costs.

Fiscal stability clauses come in different forms. One approach is to “freeze” the tax system at the time of the project agreement. If the tax system is later changed, this will imply a special treatment of a particular taxpayer, adding to the administrative burden, especially if several projects are operating under different tax systems.

Another approach is to guarantee the total investor take. If one tax is increased, this will be offset by a reduction in another tax (or in principle by paying a compensatory subsidy), which perhaps better preserves the integrity of the tax system. Still, it may be quite difficult in practice to agree on compensatory measures that can satisfy both government and investor. There are also some stability clauses that are asymmetric: protecting the investor from adverse changes to the fiscal terms but passing on benefits of economy-wide reductions in tax rates.

Fiscal stability clauses are widespread in the oil and gas sector. Of 109 countries surveyed in 1997, a majority (63 percent) provided fiscal stability clauses for all fiscal terms (see annex Table 3). A small group (14 percent) had partial fiscal stability clauses excluding income tax. Finally, a minority (23 percent) did not provide any fiscal stability clauses in project agreements (at least up until 1997). However, this does of course not prevent an investor from seeking to renegotiate fiscal terms in response to policy changes. A recent example of a country, which repealed its tax stability clause for contracts signed from 2002 onwards, is that of Kazakhstan . Tax conditions set in contracts may now be adjusted in compliance with amendments to tax laws, by the mutual consent of the government and the contractor.

Petroleum Contracts

A versatile production sharing framework can be attractive to both the contractor and government since it can be adjusted to suit particular project circumstances without changing the overarching fiscal framework. However, it might include design and administrative complexities causing a PSC to be as complex to administer as profit-based taxes. Difficulties relate particularly to the determination of allowable costs. Moreover, it is possible that the exante agreement becomes quite inappropriate as the real profitability of a project becomes known.

C. The Choice between Tax/Royalty and Production Sharing Regimes

There is no intrinsic reason to prefer a tax/royalty regime to a PSC regime, since the fiscal terms of a tax/royalty regime can be replicated in a PSC regime, and vice versa (Table 1). For example, the PSC may have an explicit royalty, or there may be a limit on cost oil that function as an implicit royalty. In a PSC regime, the contractor can be subject to the same income tax as other companies. The split of profit oil can mimic a resource rent tax. This is especially true if unrecovered costs are uplifted by an interest factor that approximates the contractor’s opportunity cost of capital. In such cases, there would be no profit oil to be split, other than the profit oil representing the implicit royalty, until the project has earned the hurdle rate of return.

Low risk to government Royalty There may be an explicit royalty; or there may be a limit on cost oil that functions as an implicit royalty.Medium risk Income tax Income tax, which may be paid out of the government’s share of production. High risk Resource Rent Tax The determination of the amount of profit oil can mimic a resource rent tax. PSCs permit the conditions governing petroleum exploration and development to be consolidated in one document. They may be particularly helpful to newcomers, not familiar with the operating environment, since the necessary provisions (including fiscal stabilization) can be consolidated in the PSC and the way in which the law will be applied can be clarified.

The PSC is a straightforward way in which contractual assurances, additional to statutory rights, can be offered to investors.

D. State Equity

A government may also participate more directly in an oil and gas project by taking equity in the project. State equity can take several forms, including: (i) a full working interest—paidup equity on commercial terms, which places the government on a par with a private investor; (ii) paid-up equity on concessional terms, where the government acquires its equity share at a below-market price, possibly being able to buy into the project after a commercial discovery has been made; (iii) a carried interest, where the government pays for its equity share out of production proceeds, including an interest charge; (iv) tax swapped for equity, where the government’s equity share is offset against a reduced tax liability; (v) equity in exchange for a non-cash contribution, for example by the government providing infrastructure facilities; and (vi) so-called “free” equity, which is a bit misleading since even the non-cash provision of equity usually results in some, more or less transparent, off-setting reduction in other taxes.

State equity participation is mainly motivated by a desire to share in any upside of a project, but can also reflect non-economic reasons. These can relate to nationalistic sentiment, to facilitate transfer of technology and know-how, or to provide more direct control over project development. But full equity participation can become a costly option when consideration is given to the resulting cash-calls.

There are also possible conflicts of interest arising from the government’s role as regulator overseeing the environmental or social impact of a project, which may differ from its objectives as a shareholder. In many instances, the government may be better off by focusing on taxing and regulating a project rather than being directly involved as an equity participant. It should also be kept in mind that tax instruments can replicate the economic impact of an equity share. For example, a carried interest is equivalent to a resource rent tax with the equity share equal to the tax rate and the interest rate on the carry equal to the threshold discount rate.

E. Indirect Taxes

The imposition of indirect taxes, such as customs duties and VAT, though often ignored in discussions of petroleum taxation, play an important role in the fiscal regime. In principle, oil and gas projects should be treated similarly to other economic activities when it comes to indirect taxation. In practice, however, the oil and gas sector is often treated differently either due to its special nature or as a fiscal incentive to attract investors.

Import duties

If there were no special treatment for import duties, these would be an attractive way for the government to secure an up-front revenue stream. Given the very substantial import needs, particularly during project development, this revenue is typically even more front-loaded than royalty payments. For the same reason, duty exemptions are highly attractive to investors to improve project economics. Duty exemptions can also be sought as a way to minimize dealings with customs officials, where foreign enterprises with substantial import needs can be an easy target for rent-seeking behavior.

Furthermore, in some transition economies, the government’s inability to honor its financial commitments under a joint partnership has led to numerous tax concessions to oil and gas companies due to its weakened bargaining position.

Cash advances required to be paid by each joint venture company to meet the net cash requirement of the join venture.See Nellor and Sunley (1994) for an illustration of this point.It is quite common that specialized equipment for exploration and development is exempted from import duties. It is advisable to restrict this exemption by requiring that the equipment is re-exported after its use. In some countries, all project-related inputs (perhaps restricted to purchases that are not available locally) receive a blanket exemption. Some countries provide guarantees against discriminatory duties being imposed on oil and gas companies, for example by applying a maximum allowable duty. This can result in reverse discrimination whereby duties on imports for petroleum projects are in effect lower than for other importers.

Value added tax

The treatment of the oil and gas sector for VAT purposes is often influenced more by administrative realities than by principles of good tax policy. In a developing country, typically a large share, if not all, of the output from a petroleum project will be exported. Combined with the very large investment needs, this can complicate the treatment for VAT purposes. If exports are zero-rated under a destination-based VAT regime, the taxpayer will likely be in a continuous net refund situation reclaiming VAT paid on investment goods or on inputs. While this in an economic sense is the correct treatment of an exporter, it may be difficult to pay refunds in a timely fashion if the administrative capacity is weak. This situation is further exacerbated by the magnitude of the VAT refunds, particularly during periods with large investment requirements.

Faced with this refund problem, many countries provide VAT exemptions for imported capital goods and sometimes imported inputs for oil and gas extraction. This treatment may also be sought for domestic suppliers to projects, though this can be particularly problematic since it opens a loophole for domestic firms to evade VAT. That said, if the capacity is not in place to administer a refund based system, it may be an unavoidable option to introduce a sector-specific exemption for capital goods, perhaps extended to certain specialized inputs used exclusively for oil and gas extraction. It is desirable that the exemption should not apply to inputs that can be easily used by other sectors in the economy, for this would open another loophole for tax evasion.

The standard international practice is to levy VAT on the destination basis, under which imports are taxed and exports are zero-rated. An exception to this practice was the treatment of trade between the new countries (other than the Baltics) formed after the dissolution of the Soviet Union, (hereinafter referred to as the “CIS countries”). In part because the former Soviet Union was viewed as a common economic space, the CIS countries adopted the origin basis for CIS trade, under which goods are taxed in the country in which they are produced.

Non-CIS trade was taxed under the destination basis.The CIS countries have now adopted See Baer, Summers, and Sunley (1996) for a discussion of the destination VAT for CIS trade.the destination basis for CIS trade, other than oil and natural gas.As Russia is a large net exporter of oil and natural gas, this special rule involves a transfer of tax revenue to Russia, primarily from the Ukraine. As a matter of tax policy, applying the origin basis to trade in oil and natural gas is an unjustified poaching of the tax base.

Export duties

Most export duties that countries levy are concentrated in a few products. These duties are sometimes justified as a means of taxing away windfall gains, as a substitute for income taxation (on agricultural products), and as a way to improve the terms of trade. Many countries have removed export duties as part of tariff reform programs aimed at establishing outward oriented trade regimes. Export duties generally are not levied on oil and gas. However, Russia levies export duties on oil, natural gas, and oil products. The oil tariff is a sliding scale tied to the Ural oil price, and the rate is adjusted every two months. Below $15 per barrel, there is no export duty. This levy, which has been justified as a revenue measure, primarily burdens producers and distorts the price of exports and domestic oil supplies. Under the current Fund program, this tax is to be removed in 2003.

F. Other Nontax Payments

A number of other nontax instruments are available, though these are often of lesser importance in terms of revenue generation. Many countries require payment of various fees; either fixed or auctioned, such as license, rental or lease fees. These are commonly paid to the petroleum department and to some extent act as an incentive for the investor to carry out exploration and development work on the granted license area. Common for oil and gas projects in many countries is the requirement to pay signature, discovery and production bonuses. The attraction to the government of bonus payments is that these are received early in the project cycle; for the same reason, they may discourage marginal investments.

However, collecting bonus payments requires little administrative effort and is a desirable way to ensure some early revenue from an oil and gas project. Auctions for exploration or development rights could in theory be a very attractive way of securing the state’s share of economic rent. However, for countries where political risk is perceived to be large, or with a high level of geological uncertainty, investors will be fewer and very risk averse prior to development. The bids received will therefore be lower than the expected net present value of a mineral deposit in a situation of no uncertainty. This could lead to demands to increase the government take if a project turns out to be more profitable than the original bid would reflect. Despite this bias, an auction can be a desirable way to administer the allocation of exploration rights among oil and gas companies, as it is done in some countries, though it would be unrealistic to rely on this as a major revenue source.

Empirical evidence on the effectiveness of auctioning exploration or development rights is mixed across countries.Although auctions have performed very efficiently in the US, they were not as successful in the UK due to a much lower number of bidders. In Venezuela, the 1997 bidding round was viewed as successful in raising government revenue, though some industry sources suggest that the winning bids were at a substantial premium.


A. Cross Country Evidence

Reflecting that there is not one optimal model for taxing oil and gas projects, countries make use of a broad range of tax and non-tax instruments. To illustrate the range of fiscal regimes,Table 2 provides an overview of current practice in a wide number of developing countries.While fiscal regimes for oil and gas exploration are strikingly diverse across countries, some general observations can be inferred. The majority of countries in the sample apply royalties in order to secure an up-front revenue stream. Moreover, while almost all countries assess royalties on an ad valorem basis, the actual rates vary from 2 percent to 30 percent; a common range for countries with royalties would be around 5-10 percent.


Oil  Revenue Sharing

Oil Revenue Sharing

The choice of tax rate reflects the typically higher economic rent in the petroleum sector. Countries without production sharing arrangements or a resource rent tax typically apply a higher income tax rate in the oil and gas sector than for other economic activities. Some countries have combined a corporate income tax with a resource rent tax, often rate-of-return based, whereas a few countries apply a higher income tax rate when oil prices exceed a certain trigger level. Some countries have provided for more lenient taxation of natural gas projects, partly reflecting lower resource rents, the typically higher investment requirement, and at times larger risk involved than under an oil project. Key issues in gas development are the identification of a market for the gas and the determination of the most economic means of transporting gas to the market.

As in many other economic sectors, investment incentives are widely available. The most common are full current expensing of exploration and/or development costs, accelerated depreciation allowances, and investment tax credits. Tax holidays or reduced tax rates are less common, but some countries do offer these particularly for smaller projects or to encourage investments in less explored regions. Many countries provide exemptions from customs duties and VAT on imports, at times only for specialized equipment to be reexported after use. Another common incentive is flexible loss carry-forward provisions, in many countries for an unlimited period of time.
Production sharing arrangements are widespread in the petroleum sector where about twothirds of the countries surveyed have this as the main core of their fiscal regime. Quite common is a formula-based system with the share of profit oil linked to the volume of production. It is typical to have at least 50-60 percent of profit oil going to the state, but in some countries a higher share applies. Countries also differ regarding limits for allowable costs the operator can recover as cost oil. In some countries, even if income taxes are nominally due, these are paid out of the state’s share of production.

The extent to which countries participate directly in projects as equity holders differs. Typically countries retain the right to take equity in a project. Often this is done on a carried interest basis, whereby the cost of the equity is paid back to the company out of production proceeds. However, many countries do not actually exercise their right to equity participation or at least not fully, in part due to the costly financial obligations that can arise from project participation, particularly when the equity interest requires the country to meet cash calls and to make other cash payments.

Some regional patterns are also apparent. In Africa, about one-half of the surveyed countries rely on production sharing. Of the other half with a tax/royalty regime, some apply a resource rent tax in addition to the corporate income tax. In Asia, production-sharing arrangements are widespread. Only a few countries in the Pacific use resource rent taxes. In the Western Hemisphere, production sharing is quite rare outside of the Caribbean, and very few countries apply resource rent taxes. There are also several Latin American countries that have reduced tax rates noticeably over the last couple of years—particularly Argentina, Chile and Peru—to attract investment. In the Middle East, the majority of countries rely on some form of production sharing, which is also common among the surveyed transition countries.
B. Evolution of Selected Fiscal Regimes

The evolution of fiscal regimes for upstream oil and gas activities in four diverse countries (Norway, Kazakhstan, Indonesia and Angola), summarized in Appendix I, provide some insights into how oil and gas taxation varies over time and across countries. There are four main features of the dynamic evolution of these fiscal regimes. First, the fiscal terms appear to have been influenced by oil prices, becoming more generous in periods of price decline and vice versa.

As declining world oil prices lead to expectations of lower profitability and reduced investment activities, there is some evidence that host country governments have responded to this by offering more attractive fiscal conditions. Whether this observation is generalized to most oil and gas producing countries in periods of sustained petroleum price changes remains to be confirmed. If so, it would imply that conservative oil and gas revenue projections should reflect an assumption of relaxed fiscal terms along with projected persistent lower oil and gas prices. Second, fiscal terms have been influenced by tax policies set in the home countries of international petroleum companies. For example, Indonesia modified the terms of its production sharing contracts in 1978 in response to the

US Internal Revenue Service (IRS) that disallowed a tax credit for “income taxes paid” by the Indonesian government on behalf of American companies, and Norway raised the Special Tax rate and restricted capital depreciation provisions in 1979, following the introduction of the US windfall profits tax. Third, bonuses have become streamlined and less important over time as a method of petroleum revenue collection. Fourth, the case studies suggest that as the petroleum fiscal system matures, the revenu regime becomes more progressive. For example, in 1972, Norway moved from a single-rate royalty regime to a multiple-rate one
based on the scale of production.

In 1995, Kazakhstan introduced the excess profits tax with a range of rates corresponding to different rates of return brackets. In 1988, Indonesia adopted a progressive production sharing scheme where the production split between the contractor and the government depended on the nature of the field and on production volumes. In Angola, the 1988 model production sharing contract provides five different share parameters between the government and the contractor, based on different rate of return brackets.
An important explanation of the wide difference in fiscal patterns observed across countries lies in their difference in bargaining power when negotiating fiscal terms with international oil and gas companies. In turn, a country’s bargaining power is derived from its particular circumstances. The strictest fiscal regimes tend to be in countries, which offer very attractive geological prospects, combined with political and macroeconomic stability (Indonesia is a good example of such a country until recently). While it can be argued that all countries embody some degree of most forms of risk from political to commercial, certain risks tend to influence the bargaining position, and hence the fiscal terms, more so in some countries than in others.
In Norway an important risk issue concerns the competitiveness of its oil and gas in highly contested markets.

Although characterized by a stable political regime and reasonably strong geological prospects, Norway must compete with several other North Sea producers (the UK, The Netherlands and Denmark) to attract international companies’ investments in North Sea exploration and production activities. The main market for North Sea oil and gas is Western Europe, a fairly saturated and competitive market. This market-based risk has likely influenced Norway to further focus on its lenient ring-fencing, interest deductibility and depreciation rules. These provisions are believed to have undermined the effectiveness of the Special Tax, which underscores the importance of combining a tax on excess rents with strict ring fencing and thin capitalization rules.
Kazakhstan is an investment location characterized by significant resource commercialization risks. Kazakhstan’s land-locked geography makes it dependent on either Russian-owned pipelines or on its ability to secure investment for, and build, alternative routes (across other jurisdictions) in order to ship its oil and gas to international markets. Transportation fees to the pipeline companies dissipate some of its petroleum sector rents across jurisdictions, leaving fewer rents to be collected by the Kazakh government. This has weakened the government’s bargaining position and has led to more relaxed fiscal terms over time, such as streamlined bonuses and the deductibility of bonuses and royalties from the income tax and the excess profits tax.

Finally, Angola—a country with strong geological prospects —is an investment location characterized by relatively high-perceived political risks. The fiscal regime concluded between investors and the government of Angola is specific to each production sharing contract, which includes a tax stability clause. Other terms of the contracts have become more discretionary over time. For instance, model production sharing contracts used to specify a maximum cost recovery share, an uplift factor and a depreciation rate for development expenditures. These provisions became determined on a contract-bycontract basis in 1997. Furthermore, the list of expenditures admissible (at the government’sdiscretion) under cost recovery has been expanded.

A broad range of fiscal instruments is available to policymakers to design a fiscal regime for the oil sector that will attract investment as well as secure a reasonable share of economic rent for the government. Some may favor greater reliance on production-based levies to ensure a steady stream of revenue for the government. Others would put greater emphasis on profit-based levies to minimize distortions. Most countries have both profit-based and production-based levies. Fiscal terms accepted by a country reflect the negotiating strength
and experience of the country, geological prospects, and the track record of previous projects.

During negotiations, potential fiscal revenue may be lowered to compensate for particular high costs of extracting oil, reflected in markets, commercial or political risk premia.
There clearly is not one optimal fiscal regime suitable for all petroleum projects in all countries. Countries differ, most importantly in regard to exploration, development and production costs; the size and quality of petroleum deposits; and investor perception of commercial and political risk. Likewise, projects may differ sufficiently that some flexibility is necessary in deriving an appropriate fiscal regime. At times, this could justify a case-bycase approach to project negotiations, though it is desirable if the chosen fiscal framework is sufficiently flexible to respond to unforeseen developments so as to minimize the need for ad hoc changes.

These factors will influence the size of the government’s revenue take: a country with large proven reserves and low exploration and development costs will be able to negotiate a higher revenue share than a country that has a short, and perhaps somewhat uneven, track record, particularly if there is uncertainty regarding the size, quality and extraction costs of its petroleum reserves.
Despite these qualifications, it is possible to outline some desirable features to target when designing a fiscal regime for the petroleum sector. Ideally, this should combine some upfront revenue with sufficient progressivity to provide the government with an adequate share of economic rent under variable conditions of profitability. This can be achieved through a tax-based system combining a corporate income tax with a rate of return based resource rent tax (or a progressive income tax), and a royalty at a modest level to secure some up-front revenue. However, it could also be achieved by a production sharing arrangement with a
moderately progressive government take linked to product prices or project rate of return.

The latter, however, may be more difficult to negotiate for countries with few successfully developed projects. Under those circumstances, a resource rent based tax system could prove more flexible while requiring less information ex-ante about potential project profitability. Still, the capacity of a particular country to competently administer a complex taxation-based system must be taken into account when designing the fiscal regime. Attempts should be made to keep the administrative burden as low as possible, while maintaining sufficient safeguards such as ring-fencing to counter tax avoidance, particularly the risk from transfer pricing.
The case studies in this paper provide useful insights into the dynamics of fiscal terms. First, there is some evidence that these react endogenously to world petroleum prices, at least to sustained medium-term changes. Second, fiscal terms set by host countries are influenced by tax policies in the home countries of oil and gas companies. Third, there may be some tendency for revenue collection schemes to become more progressive as a country’s petroleum fiscal system matures.

The government’s share of economic rent can become excessively low as countries compete to attract investment capital for oil and gas extraction, particularly if the fiscal regime is used to try to compensate for an otherwise unattractive investment environment or high political, market or commercial risk. Though the pressure to provide generous fiscal terms to attract investment can be almost irresistible, the overall investment climate is more important determinant for attracting investment than tax factors.

Moreover, there must be a lower bound for the government share from oil and gas extraction below which it would be better for the country to postpone a project rather than forego a reasonable share of the economic rent. From the perspective of the multinational oil companies, the primary concern is how attractive are the oil and gas prospects, how the fiscal terms affect their risk, what is the expected reward if petroleum is found, and how do these factors—for any particular regime—compare to investment opportunities elsewhere.

Ultimately, there is a market test for each country’s fiscal regime—can the country attract investments in its oil and sector. If not, the fiscal regime may be inappropriate for the Tax incentives may also be insufficient in determining a firm’s location decision. In a recent survey of 75 multinational companies, including 12 firms in the energy sector, most of the energy firms identified non-taxfactors, such as geology or market opportunities, as more important for the location of a foreign subsidiary country, given its exploration, development and production costs; the size and quality of petroleum deposits; and investor perception of commercial and political risk.

Evolution of Petroleum Tax Systems for Selected Countries

1. Norway1969: 35 percent compulsory state participation on a carried interest basis on all new licenses.

1972: Royalties on oil (applicable to gross revenue from a field’s total production at the production point of shipment) changed from 10 percent to a range of 8 to 16 percent. Special tax relief provisions in the offshore industry were abolished.
1974-1975: period which follows a quadrupling of oil and gas prices. Introduction of an excess profits tax, the Special Tax (designed to capture the rent from offshore petroleumactivities), of 25 percent on the full income net of the corporate income tax of 50.8 per cent. Introduction of a straight-line capital allowance of 6 years (effective after the beginning of production) used against the Special Tax. Capital also benefits from an annual depreciation of 10 percent over 15 years (capital uplift). Only 50 percent of losses incurred from other activities in Norway are deductible from offshore income. Introduction of a new governmentset price for oil, the “norm price” defined as the real market price of the same type of crude over a given period as determined by independent traders on a free market. No ring fencing provisions other than around offshore activities.

1979-1980: Further increases in oil and gas prices (which tripled from 1978 to 1982) and introduction of the US windfall profits tax strengthen the bargaining position of the Norwegian government for North Sea projects. The Special Tax rate is raised to 35 percent. Capital annual depreciation parameter and number of years reduced.
Mid 1980s: drop in oil and gas prices combined with strong geological prospects.

1987: Special Tax rate reduced to 30 percent, royalties lifted for new fields. Depreciation calculated under the Special Tax and the income tax starts from the time the expenditure is incurred. Uplift is no longer available on capital expenditure after January 1987.
1992: Major tax reform. Corporate income tax reduced from 50.8 to 25 percent while Special Tax rate is raised to 50 percent. Deductibility of financial costs, applied to oil companies and not to individual prospects, is limited to 80 percent of external financing. 5 percent depreciation allowance over 6 years is allowed as additional depreciation under the Special tax. Deductions became more important when the Special Tax gained prominence relative to the corporate income tax, which led to a gradually declining government take.

2. Kazakhstan

1991: year of the initial main contract negotiated between the Kazakh government and a major international oil company. Three types of royalties: fixed (US$20 million the first year, US$30 million the second year and US$40 million the third and the fourth year), base (18 percent after four years) and additional (25 percent if the nominal return exceeds 17percent). Three types of bonuses (signing, commercial discovery and mining). Maximum corporate income tax of 30 percent.

1995: Tax Decree. Introduces the excess profits tax, which starts with an internal rate of return of 20 percent and comprises up to four rates applicable to thresholds stipulated in individual contracts. Introduces ring fencing.
1996: Petroleum Law. Introduces a tax stability clause.

1997: Amendments to the Tax Decree. Royalties and the signature bonus become deductible from the income tax and the excess profits tax. The commercial discovery bonus and the mining bonus are repealed. Repeal of the tax stability provision restoring economic interests of the parties if international treaties force chnages in the original terms of the contract.
2002: new tax code. The entire tax stability clause is repealed for contracts signed after December 31, 2001.

3. Indonesia

Production-sharing contracts (PSCs) were first used in Indonesia. They have some of the world’s strictest financial and fiscal terms, which are counterbalanced by the country’s great hydrocarbon potential and the generally cooperative nature of the state owned company Pertamina and the Indonesian government (Gao (1994)).
1960-1975: First generation PSCs. Cost recovery is limited to 40 percent of annual production with the remainder of the production split 65/35 in favor of the government. Carry forward of unrecovered costs allowed, but not uplift factor. Recoverable operating costs exclude interest payments on debt.
In 1972, some PSCs provided a formula maintaining the 65/35 split up to a base level, beyond which it escalated when production reached certain levels. Oil price used for cost recovery and tax calculation purposes set by the government according to an OPEC-type guide price. Applicable to gross proceeds at the wellhead net of transportation and marketing costs, non-well associated operating costs and depreciation of non-well facilities.

Bonuses: Bonus payments vary considerably between individual PSCs. Bonus payments are borne solely by the contractor and cannot be included in the operating costs, which are recoverable from production, but can be charged against tax liabilities once profitable operations commence. The signature bonus ranges between $1 million and $5 million.
There may be 2 to 5 production bonuses triggered by the volume of production, from a low of 0 to 50,000 barrels per day to a high of 100,000 to 500,000 barrels per day. Total bonus commitments commonly range from $15 million to $50 million.

Ring fence provision.

Domestic market obligations: since 1968, compulsory for all foreign companies. The quantity supplied by each company varies according to its own production volume and inversely to overall Indonesian production, providing that the pro-rata quantity does not exceed 25 percent of total production from its contract area. The oil price for domestic supply is determined as follows: for the first five years of production, it equals the price received by the contractor for the recovery of operations costs (export price). After the first five years of production, the price is the cost plus $0.20 per barrel.

1976-1988: Second generation PSCs, which terms are affected by the oil price crisis of 1973 and the US IRS ruling disallowing tax credits for Indonesian corporate taxes paid by Pertamina, on behalf of US oil companies, out of the government’s share of production.
Abolition of cost oil, increase in government share from 65 to 85 percent of production after cost recovery, introduction of a tax on foreign companies and of a number of investment incentives.

1976: Stricter terms for the new cost recovery feature based on a double-declining balance depreciation method. Cost recovery period extended from 7 to 14 years. Interest expenditures are treated as a recoverable operating costs subject to the following limitations: financing must be with non-affiliates, loans should be obtained at rates not exceeding prevailing commercial rates, financing plans and amounts must be included in each year’s budget of operating costs for the prior approval of Pertamina.
1977: Investment credit of 20 percent of production subject to a guarantee to the government of a 49 percent share of gross revenue over the life of the field.

1978: contractors’ pre-tax profit share of 34.0909 becomes subject to the corporate income tax rate of 45 percent and a 20 percent tax on interest, dividends and royalties after deducting the corporate tax. PSC set a new pre-tax split at 65.9091 for Pertamina and 34.0909 for contractors.The net effect of the tax change resulted in a post-tax split of 85/15 in favor of Pertamina.
1984: PSCs concluded thereafter are subject to a new income tax of 35 percent of taxable income and a dividend tax of 20 percent on the balance. Profit split is reset at 71.1853 for Pertamina and 28.8642 for the contractor in order to compensate for the lower tax rate and keep the post-tax split unchanged at 85/15. Investment credit decreases to 17 percent subject to a guarantee to the government of a 25 percent share of gross revenue over the life of the field.

1988 onwards: Third generation PSCs. Decreasing petroleum prices, increasing production costs and tightened international competition for scarce investment funds influenced modifications to the PSCs. First Tranche Petroleum (FTP), increased investment credit, progressive sharing splits, deregulation in certain areas and investment promotion.
1988: Introduction of First Tranche Petroleum (FTP), a portion of oil/gas production amounting to 20 percent to be split between Pertamina and the contractor every year on the basis of the applicable profit split ratio before any deduction of cost recovery. The FTP constitutes, in effect, a royalty in kind which varied according to the volume of production and the applicable sharing ratios. Introduction of new pricing formula under which the governments sets the oil price on the basis of monthly average spot prices for a basket of five internationally traded crude oils.

Domestic production requirement. Nominal payment for the old oil was increased in 1989 to 10 percent, and in 1992, to 15 percent of the export price for both new and old oil for all PSCs. It was raised again in 1993 to 25 percent of the export price for old oil from frontier and deep-water fields.
Profit oil shares restructured by the 1988, 1989, 1992 and 1993 incentive packages. Progressiveness in production sharing replaces the previous fixed split. For contracts signed after 1988, the production split may slide between 75/25 and 90/10 depending on the nature of the fields and the production volumes. Nevertheless, the original 85/15 split seems to remain predominant over other ratios.

Requirements for bonus payments have been declining sharply over the years. Total bonus payments reported in the 46 PSCs concluded in the first peak years of signing 1979-82, $306 million, are much higher than the total of $60 million from the 45 PSCs concluded in 1987-1990.
4. Angola

Main modifications in the model PSC contract from 1988 to 1997 include relaxing the profit sharing parameter which becomes determined on a contractual basis, increasing the range of admissible expenses for cost recovery purposes, eliminating the price cap excess fee provision and increasing the rate of straight line depreciation of development expenses prior to leaving their uplift factor and depreciation rate determined on a contractual basis.

Bonus: Signature bonus, to be determined on a contractual basis. Not recovered or amortized for cost recovery purposes. Development area rental: $300 per km Purchase rights: State company has the right to purchase the contractor’s oil, for an amount equivalent in value to the petroleum income tax due by the contractor to the Ministry of Finance.
Fiscal regime: not specified in the model PSA. To be established by concession decree. Contractor is responsible for all taxes except the petroleum income tax. Tax stability clause: government is open to revisions subject to the fact that it does not impact negatively on either party’s economic benefit. SONANGOL reimburses the contractor for increases in clearance, stamp duty and/or the statistical levy applicable to imports.

Cost recovery: Maximum of 50 per cent per year as cost recovery crude oil (provision, which was in the 1988 model contract, stayed throughout until 1997 when it was replaced by an unspecified parameter). Ring fencing for development expenditures. Uplift factor of 1.4 to development expenditures, which are then depreciated linearly (on an equal annual installment basis) at 20 percent per year starting in the year where the expenditure is incurred (in 1991, the uplift is same as before but the resulting amount is recoverable at the rate of 25 percent in annual installments, for offshore agreements). The uplift and depreciation parameters are no longer specified in the model PSA agreement of 1997.
No ring fencing for exploration expenditure. Recoverable from unused balance of cost recovery crude oil existing from each development area after recovery of development expenditures and production expenditures, up to 50 percent. In each year, exploration expenditures shall be recoverable first from any cost recovery crude oil balance having the most recent date of commercial discovery and then any balance of total exploration expenditure not already recovered shall be recoverable in sequence from development areas
with the next most recent dates of commercial discovery.

Nonadmissible expenditures: signature bonus, petroleum income tax, contributions and taxes on salaries and wages of workers employed by the operator. Loss carryover: unchanged throughout the considered period. 5 years for development expenditures, after which contractor’s share of crude oil is increased to allow for cost recovery. Indefinite carry forward with no change in cost recovery parameter for other types of expenditure.
Admissible costs: between 1991 and 1997, the list of admissible expenditures under cost recovery widens. Many technical health, safety and environmental audits items (provided by affiliates of operator or SONANGOL) as well as communication studies. Range of items falling under costs recoverable only with prior approval of SONANGOL has increased.

Element of discretion (includes costs incurred before the effective date of the agreement, promotional and advertising expenses, cost for renewal of contracts without prior authorization). Production sharing: crude oil produced and saved in a quarter from each commercial discovery and its development area and not used in petroleum operations less cost recovery crude oil from the same area is referred to as “development area profit oil” and shared between SONANGOL and contractor according to the after tax nominal rate of return
achieved in the preceding quarter. Model PSA has 5 different rates of return brackets with different share parameters between SONANGOL and the contractor. Parameters not specified in the model PSA. Rate of return is determined on the basis of the accumulated compounded net cash flow for each development area.