Thursday, December 29, 2011

Indonesia Energy Report

Indonesia has the largest population in Southeast Asia and the fourth largest population in the world (behind China, India, and the United States). It is also the world's third-fastest growing economy. Although Indonesia has been a net importer of oil since 2004, it is the sixth largest net exporter of natural gas, and the second largest net exporter of coal. However, as a result of inadequate infrastructure and Indonesia's complex business environment, Indonesia has struggled to attract investment sufficient to meet its energy development goals.

Indonesia Map




Indonesia's total primary energy consumption grew by nearly 50 percent between 1999 and 2008. Oil continues to account for the most significant share of Indonesia's energy mix, at 44 percent in 2009. Coal consumption has tripled over the decade, accounting for 29 percent of total energy consumption in 2008, surpassing gas as the second most consumed fuel.

Total Primary Energy Consumption Indonesia 




Indonesia is also a significant consumer of traditional biomass in its residential sector, particularly in the more remote areas that lack connection to Indonesia's energy transmission networks (power grids and pipelines, for example). The International Energy Agency estimates that combustible renewables and waste account for about a quarter of total primary energy supply.




Oil




Indonesia is currently a net importer of both crude oil and refined products. Indonesia's crude oil production has been declining since 1998, due to the maturation of the country's largest oil fields and failure to develop new, comparable resources. Indonesia was a member of the Organization of Petroleum Exporting Countries (OPEC) from 1962 to 2009. In 2004, the country became a net oil importer and in January 2009, suspended its OPEC membership.

Oil Production Consumption Indonesia 


Sector Organization


Indonesia's upstream oil sector is dominated by several international oil companies - in particular Chevron, Total, Conoco Phillips, Exxon, and BP. Chevron is the largest single oil producer in Indonesia, accounting for more than 40 percent of the country's total crude production. PT Pertamina, Indonesia's state-owned integrated energy supply company, accounted for approximately 15 percent of 2009 crude and condensate production, making it the second largest producer in the country.




The Indonesia Ministry of Energy and Mineral Resources is responsible for entering into production sharing contracts (PSCs), while the state-owned legal entity BPMigas serves as the upstream regulator that manages and implements these agreements. Indonesia's 2001 Oil and Gas Law significantly restructured Indonesia's upstream oil and gas sector - most notably transferring the upstream regulatory role from PT Pertamina to BPMigas. Although PT Pertamina continues to be wholly state-owned, the 2001 law also led to its establishment as a limited liability corporation in 2003. Senior Pertamina officials have indicated plans to divest two of its subsidiaries by about 20 percent in an initial public offering, but details and timing have not been confirmed.




In addition to its upstream activities, PT Pertamina operates nearly all of Indonesia's refinery capacity, procures crude and products imports, and supplies products to the domestic market. While Pertamina's monopoly in the retail market ended in 2004, the company continued to be the sole distributor for subsidized fuels until early 2010.


Exploration and Production


According to Oil & Gas Journal, Indonesia had 3.9 billion barrels of proven oil reserves as of January 2011. In 2010, total oil supply averaged just over one million barrels per day (bbl/d). Of this total, about 943,000 bbl/d was crude oil and lease condensate production. Crude and condensate production has declined at an annual average rate of 4.1 percent between 2000 and 2010.




Indonesia's two largest producing oil fields are the Minas and Duri fields, located on the eastern coast of Sumatra. Chevron operates both fields with a 100 percent working interest under the Rokan Production Sharing Agreement. Producing since 1952 and 1955 respectively, production at both fields is in decline, even with the employment of enhanced oil recovery techniques at both fields to bolster production. Chevron uses steam injection enhanced oil recovery for 80 percent of the Duri field, one of the largest steamflood projects in the world.




The most significant recent discovery with the potential to counteract some of Indonesia's production decline is the Cepu Block of East and Central Java. Exxon Mobil is the operator of the Cepu PSC (45 percent interest), in a joint venture with PT Pertamina's E&P unit (45 percent working interest) and four local government companies (10 percent interest). Cepu is estimated to contain 600 million barrels of recoverable liquids, and to have a peak production of 165,000 bbl/d. Although discovered in 2001, the project has encountered several delays in the development process, and Exxon recently revised its goal for peak production from 2012 to 2014. Banyu Urip is currently the only producing field in the Cepu PSC, and as of January 2010, had reached a production level of about 18,000 bbl/d.




BPMigas and the Indonesian government have introduced policies aimed at increasing investment in the country's upstream sector - in particular via investment incentives and improving the flexibility of the PSC bidding process. However, the upstream investment environment is still considered to be risky, and 2009 and 2010 licensing rounds were disappointing. Recent events that caused particular concern were Parliament's attempts to mandate cost recovery caps for PSCs, as well as the government's cabotage rule - a shipping regulation requiring all marine vessels to carry the Indonesian flag. The government has since announced that cost recovery caps would be removed, and that implementation of the cabotage rule will except oil and gas vessels. However, Indonesia failed to meet its 2010 production goal of 965,000 bbl/d of crude and condensate production, and signed only 21 new oil and gas PSCs in 2010, relative to 34 in 2008.


Refining


Indonesia has a refinery capacity of just over one million bbl/d, according to Oil & Gas Journal. Spread across eight refineries owned by PT Pertamina, the majority of the country's refinery capacity is located on Java and Sumatra. The three largest refineries are Cilacap (348,000 bbl/d) in Central Java, Balikpapan (260,000 bbl/d) in East Kalimantan, and Bolongan (125,000 bbl/d) in West Java. Refinery output goes primarily to the domestic market, but meets only about 70 percent of domestic consumption. Pertamina plans to eliminate the need for product imports by 2017, and in the last few years has announced several refinery upgrade, expansion and greenfield projects in support of this goal. However, most of these projects have been delayed, as low refining margins and lack of government financial incentives have deterred investment from international partners.




Pertamina signed an agreement with Kuwait Petroleum Corporation in August of 2010 to study an upgrade to the Bolongan refinery in West Java. The company is also in discussion with Saudi Aramco to build a new 200,000-300,000 bbl/d refinery in East Java, though Saudi Aramco indicated late in 2010 that Indonesia's government would need to provide more incentives in order to secure the company's participation. Pertamina's planned 300,000 bbl/d Banten Bay refinery in Bojanegoro is currently administered by a joint venture with Iran's Oil Refining Industries Development Company and Malaysia's Petrofield Refining - but the project was recently evaluated as being "economically infeasible" by Pertamina leadership.




The above-mentioned projects would all be supported by some level of guaranteed crude supply from Kuwait Petroleum Corporation, Saudi Aramco, and the National Iranian Oil Company respectively. These sources are vital for project viability as Indonesia's domestic crude production continues to lag. However, after years of delays and failed partnerships, there is little confidence in the mid-term completion of any of these projects, and none are expected to be online prior to 2015. Upgrades to existing refineries may continue to move forward - for example, Cilicap's 62,000 bbl/d residual fluid catalytic cracking unit still appears to be on track for 2013 or 2014 completion.


Consumption


Consumption of refined products grew at a fairly steady 4.7 percent average annual growth rate between 1995 and 2005, but declined by about two percent in both 2006 and 2007, largely as a result of the 126 percent increase in the price of subsidized fuel implemented in 2005. The 2005 price increases - and the removal of fuel subsidies for large industrial consumers - were part of President Yudhoyono's early attempts to gradually eliminate fuel subsidies. Consumption increased in both 2008 and 2009, exceeding 1.3 million bbl/d in 2009.




Fuel subsides will account for nearly ten billion dollars in 2010, or about ten percent of the government's tax revenues. In December of 2010 the Indonesian parliament approved a measure to remove fuel subsidies for all vehicles excluding motorcycles and public transportation vehicles. Cash transfers will be used to ease the impact on the economically disadvantaged. The policy was initially slated for April 2011 implementation in the greater Jakarta area, and nationwide by 2013. However, implementation was indefinitely delayed in March 2011 due to concerns over the effect on the rate of inflation.


Natural Gas


According to Oil & Gas Journal, Indonesia had 106 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2011. Indonesia is the fourteenth largest holder of proven natural gas reserves in the world, and the third-largest in the Asia-Pacific Region. Although domestic consumption of natural gas has nearly doubled since 2004, Indonesia continues to be a major exporter of pipeline and liquefied natural gas (LNG).


Sector Organization


The regulatory structure that shapes Indonesia's upstream oil sector also forms the basis for the gas sector (see Oil: Sector Organization). BPMigas serves as the upstream regulator, and state-owned PT Pertamina - though still active in upstream exploration and production - no longer plays a regulatory role. Pertamina accounts for about 15 percent of natural gas production. International oil companies such as Total, ConocoPhillips, and ExxonMobil dominate the upstream gas sector, while natural gas transmission and distribution activities are carried out by the state-owned utility Perusahaan Gas Negara (PGN).


Production


In 2009, Indonesia produced 2.6 Tcf of dry natural gas. Production has grown at an average annual rate of about 1.5 percent over the previous two decades, and Indonesia's 2009 gas production was the eleventh-highest in the world. A little more than half of Indonesia's 2009 production came from offshore fields, although the government estimates that more than 70 percent of the country's conventional gas reserves may be located offshore. An increasingly large majority of Indonesia's natural gas production has come from non-associated fields in recent years, with associated gas accounting for about 18 percent of gross production in 2009.


Indonesia Dry Natural Gas Production Consumption 


Indonesia's geography presents a challenge to resource development, because the archipelago nation's most prolific blocks of conventional gas reserves are located far from its major demand markets. The most significant areas for current natural gas production are:


East Kalimantan's offshore fields, particularly the Mahakam PSCs operated by Total
South Sumatra, particularly the onshore Corridor PSC operated by Conoco Philips
Aceh and North Sumatra, including Exxon Mobil's declining offshore Arun field
South Natuna Sea, offshore Block B operated by Conoco Phillips




In 2009, East Kalimantan's offshore Mahakam PSCs accounted for about a third of gross production.




In addition to expansion of current projects, there are several major new gas projects in development for the next decade. Total and Petronas (Malaysia) recently joined ExxonMobil and Pertamina to develop the Natuna D-Alpha field in the East Natuna Sea. Pertamina expects the project to start by 2021, and has estimated that East Natuna in total holds 46 Tcf of gas. However, the field contains about 70 percent carbon dioxide, significantly tightening production margins for its developers. Chevron is pursing the deepwater Gendalo-Gehem project with partners Eni (Italy) and Sinopec (China). At its peak, the project - which spans four PSC blocks - may produce 400 Bcf per year. The project is Indonesia's first deepwater gas project. According to BPMigas, the first stage of the project will come from the Bangka field, and may commence as early as 2014. Inpex (Japan) received permission to begin development in its Masela block, which is estimated to hold about 14 Tcf of natural gas. This offshore block in the Arafura Sea will serve export markets through the planned associated LNG terminal (see LNG section), and is expected to begin production in 2016.




In addition to its considerable conventional gas resources, Indonesia also holds an estimated 453 Tcf of coalbed methane (CBM), a type of unconventional gas whereby methane - the primary component of natural gas - is extracted from coal beds. CBM reserves are located relatively close to Indonesia's population centers, primarily in South Sumatra and Kalimantan. The government began awarding PSC's in 2008, though all are still in exploration phase. However, first production is expected to begin in some of the PSCs held by local companies in late 2011 and 2012. Though local consortiums hold many of the existing CBM PSCs, foreign majors BP, Eni (Italy), and Dart Energy (Australia) also hold shares in Indonesia's CBM blocks.


Exports


Indonesia was the world's sixth largest net exporter of natural gas in 2009. Although the majority of Indonesia's gas exports are transported as LNG, Indonesia also exports about a quarter of its gas exports via pipeline to Singapore, with which it has two pipeline connections: one from its offshore fields in the West Natuna Sea, and the other from the Grissik gas processing plant in Sumatra. These pipelines have a combined capacity of approximately 400 Bcf/y and deliver gas to Singapore under long-term contracts, both set to expire around 2020. However, as part of its efforts to secure its own domestic supply, the Indonesian government has expressed an interest in negotiating a reduction in the volumes of these contracts.




The remaining three-quarters of Indonesia's gas exports - excluding a small amount of pipeline exports to Malaysia - are exported as LNG. Japan is the major destination for Indonesia's LNG exports, accounting for about 65 percent of total LNG exports, but South Korea and Taiwan are also significant importers (see Liquefied Natural Gas for more information).


Consumption and Distribution


Indonesian gas production initially was geared towards exports, but the country's declining oil production has driven an effort to shift increasing volumes toward domestic consumption. In 2009, Indonesia consumed 1.3 Tcf of natural gas, or about half of its total dry gas production. Although the industrial sector accounts for the largest portion of domestic consumption, the power sector is expected to be the most significant driver of future consumption growth.




Indonesia's gas distribution utility Perusahaan Gas Negara (PGN) currently operates more than 3,500 miles of natural gas transmission and distribution pipelines. However, domestic distribution infrastructure is almost non-existent outside of PGN's Java and North Sumatra strategic business units. According to PGN, in 2009 there was over 400 Bcf of unmet demand for gas among domestic industrial and electric power consumers.




PGN began operations of the South Sumatra-West Java pipeline in 2008, providing an important link between the gas producing region of South Sumatra and the densely populated market of West Java. The Grissik-Duri pipeline is another important domestic transmission pipeline, as it provides gas to Chevron's Duri (see Oil: Exploration and Production) field for its steamflooding and power generation activities. A pipeline problem in September of 2010 resulted in a production outage, which has since been cited as a contributing factor to Indonesia's failure to meet its 2010 oil production goals.


Liquefied Natural Gas


Indonesia was the third-largest exporter of liquefied natural gas in 2009, following only Qatar and Malaysia. There are three operational liquefaction terminals in Indonesia, with a combined production capacity of about 1.6 Tcf (32 million metric tons (MMT)) per year. In 2009, Indonesia exported about 950 Bcf of LNG.




The Bontang LNG terminal in East Kalimantan is the largest in Indonesia at about 1.1 Tcf/y (22.6 MMT/y), and one of the largest in the world. Bontang delivered its first cargo in 1977, and was followed shortly thereafter (1978) by the Arun liquefaction terminal in Northern Sumatra. Due to a lack of sufficient additional gas reserves in the Arun field, LNG exports from the Arun plant have been declining in recent years, and are expected to stop altogether by 2014. The newest addition, BP-operated Tangguh in Western Papua, came online in July of 2009 and exported almost 330 Bcf in 2010. BP had originally intended to add a third train to Tangguh's first two trains, but has not yet proceeded with plans for this project.


Indonesia Liquefaction Capacity


The next anticipated addition to Indonesia's liquefaction capacity is the Donggi-Senoro LNG plant in Central Sulawesi. The project developers (Mitsubishi, Kogas, Pertamina, and Medco) signed a final investment decision in early 2011, and the 370 Bcf/y (2.5 MMT/y) plant is expected to be commercial in 2014. Inpex, a Japanese company, received government approval at the end of 2010 for the Masela liquefaction terminal in the Arafura Sea, but has delayed the expected startup date of the floating terminal until 2018.




LNG exports have been a politically charged topic in Indonesia, due to the perception of LNG exports removing much-needed gas from the domestic market. The expected growth in gas demand, in addition to the currently unmet demand, has led the government to pursue policies for securing domestic supplies for the local market. The Donggi-Senoro plans received government approval only after 30 percent of the output was designated for domestic consumption. Similarly, a third of the output from Inpex's planned Masela floating LNG liquefaction terminal will be designated for the domestic market, according to regulator BPMigas. Indonesia also plans to reorient the output from the Bontang LNG plant - which is relatively centrally located - into the domestic market over the next decade. Though the plant will remain operational, it will send LNG within Indonesia - and no longer serve export markets by 2020.




In order to have more flexibility to secure supplies of both domestic and foreign LNG, plans for several LNG receiving terminals are underway in Indonesia. The first regasification terminal, a 143 Bcf/y (3.0 MMT/y) joint-venture between Pertamina and PGN, will supply the Jakarta market starting in the first quarter of 2012. Pertamina also plans to invite bids for an additional receiving terminal of similar size to serve East Java. In addition, Pertamina and PLN (Indonesia's state electricity firm) have announced plans to develop eight LNG receiving "mini terminals" by 2015, with a total capacity of 67 Bcf/y (1.4 MMT/y). These terminals will be scattered throughout the eastern region of the island nation, and are intended to guarantee supply of natural gas for electricity plants.




Coal




According to EIA estimates, Indonesia has 4.8 billion short tons of recoverable coal, of which the vast majority is located in Sumatra and East and South Kalimantan. Government and industry estimates suggest that the resource base may be considerably higher than this amount. Indonesian coal production - which is primarily bituminous or sub-bituminous in rank - has approximately quadrupled between 2000 and 2009, reaching 333 MMst in 2009. In the same year, Indonesia consumed 77 MMst of coal, which was less than a quarter of its production, but more than three times the consumption level in 2000. Power plants accounted for nearly two-thirds of 2009 total coal sales. Electricity sector demand for coal is expected to more than double by 2014 as a result of coal-fired generation capacity additions.


Indonesia Coal Production Consumption


Although coal consumption has grown significantly in the last decade, the majority of additional production has gone towards exports. In order to guarantee sufficient domestic supply, the Indonesian government has set a domestic market obligation of 24 percent for producers. Indonesia is now the second-largest exporter of coal (after Australia) on the international market, and is the largest exporter of thermal coal used for power plants. Indonesia's coal exports primarily serve Asian markets, with about 70 percent of 2009 total exports being sent to China, Japan, Taiwan, and other Asian markets. In 2010, Indonesia was the leading source of Chinese coal imports.


World Top five Coal Exporter




Electricity




Indonesia had 27.8 gigawatts of installed generating capacity in 2008. Indonesia generated 122 billion kilowatthours (Bkwh) of electricity during 2008, of which 86 percent came from conventional thermal sources (oil, natural gas, and coal), eight percent from hydroelectric, and six percent came from geothermal and other renewable sources. Of the conventional thermal total, coal accounts for the largest share at 47 percent, followed by gas at 33 percent, and oil at 19 percent.


Indonesia Electricity Generation by Type




State-owned electric utility PT PLN (Perusahaan Listrik Negara) is the most significant company in the electric power sector. PLN owns and operates 86 percent of the country's generating capacity through its subsidiaries, and maintains an effective monopoly over distribution activities. Although the most recent 2009 Electricity Law ends PLN's distribution monopoly, sufficient implementing regulations to support this law have yet to come into effect.




Indonesia's generating capacity has increased by more than a quarter in the decade leading up to 2009. However, as of 2009, only 65 percent percent of Indonesia's population has access to electricity. In addition, because capacity growth has lagged behind the pace of electricity demand growth, grid-connected areas have also suffered from power shortages. Investment in Indonesia's power sector had lagged for several reasons, including inadequate supporting infrastructure, difficulty obtaining land-use permissions, subsidized tariffs, and an uncertain regulatory environment.




In order to address the capacity shortage, in 2006, the government embarked upon the first stage of its "fast track" plan, designed to add 20 additional gigawatts to the grid by 2014. The first stage, which includes 10 gigawatts of primarily coal-based generation, was initially set for completion in 2010 - though subsequent delays have led to a revised completion date of 2013. The second phase, which includes an additional 10 gigawatts to be completed by 2014, includes more cleaner sources of generation such as natural gas and renewables. Unlike in many other countries, Indonesia's government is encouraging an increased use of coal in the power sector, due to its relatively abundant domestic supply, and in order to reduce the use of expensive diesel and fuel oil.


Top Geothermal Electricity Generating Countries




Indonesia's power sector is notable for its significant level of geothermal power, and was the third-largest geothermal generator in the world in 2008. However, Indonesia's 2008 capacity of approximately one gigawatt falls substantially below its available resource, which the government has estimated to be sufficient to generate 28 gigawatts. Government plans to increase the use of renewable energy to 15 percent of the electricity portfolio by 2025 are centered on development of geothermal resources. The second phase of the fast track plan includes additional geothermal capacity of nearly four gigawatts by 2014, most of which will be operated by independent power producers.

Thursday, December 22, 2011

Nigeria Energy Report

The Nigerian economy is heavily dependent on the oil sector which, according to the International Monetary Fund (IMF), accounts for over 95 percent of export earnings and about 40 percent of government revenues. The oil industry is primarily located in the Niger Delta where it has been a source of conflict. Local groups seeking a share of the oil wealth often attack the oil infrastructure and staff, forcing companies to declare force majeure on oil shipments. At the same time, oil theft, commonly referred to as "bunkering", leads to pipeline damage that is often severe, causing loss of production, pollution, and forcing companies to shut-in production. The industry has been blamed for polluting air, soil and water leading to observed losses in arable land and decreasing fish stocks.

Niger Delta Oil Infrastructure


In addition to oil, Nigeria holds the largest natural gas reserves in Africa but has limited infrastructure in place to develop the sector. Natural gas that is associated with oil production is mostly flared but the development of regional pipelines, the expansion of liquefied natural gas (LNG) infrastructure and policies to ban gas flaring are expected to accelerate growth in the sector, both for export and domestic use in electricity generation.


In order to remedy some of the oil, natural gas and electricity industry problems, the Nigerian government is currently debating a Petroleum Industry Bill (PIB) that is designed to reform the entire energy sector (see oil section). The Bill was first introduced in 2009 and although parts of the PIB have recently been made into law, the Bill in its entirety continues to be debated by the National Assembly. This ongoing debate had delayed investments in oil exploration, project development and has also affected the natural gas sector by delaying planned liquefied natural gas (LNG) projects.

Energy Consumption by type - Nigeria

According to the International Energy Agency (IEA), in 2008, total energy consumption was 4.4 Quadrillion Btu (111,000 kilotons of oil equivalent). Of this, combustible renewables and waste accounted for 81.3 percent of total energy consumption. This high percent share represents the use of biomass to meet off-grid heating and cooking needs, mainly in rural areas. IEA data for 2009 indicate that electrification rates for Nigeria were 50 percent for the country as a whole – approximately 76 million people do not have access to electricity in Nigeria.

Nigeria has vast natural gas, coal, and renewable energy resources that could be used for domestic electricity generation. However, the country is lacking in policies to harness resources and develop and/or improve the electricity infrastructure. The Nigerian government has had several plans to address the need for power, including a recent announcement to create 40 gigawatts (GW) of capacity by 2020 (compared to 2008 installed capacity of 6 GW). Much will depend on the ability of the Nigerian government to utilize currently flared natural gas.

Oil

According to the Oil and Gas Journal, Nigeria had an estimated 37.2 billion barrels of proven oil reserves as of January 2011. The majority of reserves are found along the country's Niger River Delta and offshore in the Bight of Benin, the Gulf of Guinea, and the Bight of Bonny. Current exploration activities are mostly focused in the deep and ultra-deep offshore with some activities in the Chad basin, located in the northeast of the country.


Since December 2005, Nigeria has experienced increased pipeline vandalism, kidnappings and militant takeovers of oil facilities in the Niger Delta. The Movement for the Emancipation of the Niger Delta (MEND) is the main group attacking oil infrastructure for political objectives, claiming to seek a redistribution of oil wealth and greater local control of the sector. Additionally, kidnappings of oil workers for ransom are common and the Gulf of Guinea is also an area that has seen incidents of piracy. Security concerns have led some oil services firms to pull out of the country and oil workers unions to threaten strikes over security issues.


The instability in the Niger Delta has caused significant amounts of shut-in production and several companies to declare force majeureon oil shipments. EIA estimates Nigeria's nameplate oil production capacity to have been close to 2.9 million barrels per day (bbl/d) at the end of 2010 but as a result of attacks on oil infrastructure, daily crude oil production ranged between 1.7 million and 2.1 million barrels. Disruptions have been attributed to direct attacks on oil infrastructure as well as pipeline leaks and explosions resulting from bunkering activities.


Towards the end of 2009 an amnesty was declared and the militants came to an agreement with the government whereby they handed over weapons in exchange for cash payments and training opportunities. This amnesty has led to decreased attacks and some companies have been able to repair damaged oil infrastructure. However, the lack of progress in job creation and economic development has led to increased bunkering and other criminal attacks, which can significantly damage oil infrastructure.

Considerable attention has been drawn to the environmental damage caused by oil spills in the Niger Delta. According to the Nigerian National Oil Spill Detection and Response Agency (NOSDRA) approximately 2,400 oil spills had been reported between 2006 and 2010 that resulted from sabotage, bunkering and poor infrastructure. The amount of oil spilled in Nigeria has been estimated to be around 260,000 barrels per year for the past 50 years according to a report cited in the New York Times.

The oil spills have caused land, air, and water pollution severely affecting surrounding villages by decreasing fish stocks, contaminating water supplies and arable land. More recently, the United Nations Environment Program (UNEP) released a study on Ogoniland and the extent of environmental damage from over 50 years of oil production in the region. The study confirmed community concerns regarding oil contamination across land and water resources, stating that that the damage is ongoing and estimating that it could take 25 to 30 years to repair.

Production

In 2010, total oil production in Nigeria was slightly over 2.46 million bbl/d, making it the largest oil producer in Africa. Crude oil production averaged close to 2.15 million bbl/d for the year. Recent offshore oil developments combined with the restart of some shut-in onshore production have boosted crude production to an average of 2.17 million bbl/d for the month of July 2011.

Planned upstream developments should increase Nigerian oil production in the medium term but the timing of these startups will depend heavily on the PIB and the fiscal/regulatory terms it imposes on the oil industry. Many of the planned projects described below have already been delayed.

Nigeria Upcoming Oil Projects 


* Final investment decision expected in 2011

** Expansion of existing Agbami field- drilling activities expected to continue through 2014 (Chevron)

Sources: Oil and Gas Journal; IEA Medium Term Oil Market Report; Wood Mackenzie; Total; Chevron;Rigzone; Business Week.

As a member of the Organization of Petroleum Exporting Countries (OPEC), Nigeria has agreed to crude oil production limits that have varied over the years but are currently set at 1.673 million bbl/d. OPEC quotas do not appear to have an impact on production volumes or investment decisions to the same degree as unrest in the Niger Delta.





Exports

In 2010, Nigeria exported approximately 2.2 million bbl/d of total oil and 1.8 million bbl/d of crude oil. Nigeria is an important oil supplier to the United States. Over 40 percent of the country's oil production (980,000 bbl/d of crude oil, and slightly over 1 million bbl/d of total oil and products) is exported to the United States making Nigeria the 4th largest foreign oil supplier to the United States in 2010. The light, sweet quality crude is a preferred gasoline feedstock. Consequently, disruptions to Nigerian oil production impacts trading patterns and refinery operations in North America and often affect world oil market prices.

Nigeria Oil Production and Consumption 

Available information indicates that additional importers of Nigerian crude oil include Europe (20 percent), Asia (17 percent), Brazil (8 percent), and South Africa (4 percent). Despite shut-in production, Nigerian trade patterns appear to have remained stable over the past several years, most of which can be attributed to capacity additions combined with slightly decreasing domestic consumption and shifting world demand.





Sources: Global Trade Atlas, APEX (Lloyd's), FACTS Global Energy, EIA


According to the Energy Intelligence Group's International Crude Oil Market Handbook, Nigeria's export blends are light, sweet crudes, with gravities ranging from API 29 - 47 degrees and low sulfur contents of 0.05 - 0.3 percent. Most Nigerian crudes trade at a premium to Brent, the North Sea benchmark crude.

Refining

In 2010, Nigeria consumed approximately 280,000 bbl/d of oil. The country has four refineries (Port Harcourt I and II, Warri, and Kaduna) with a combined capacity of around 450,000 bbl/d. As a result of poor maintenance, theft, and fire, none of these refineries have ever been fully operational. In 2009 and some of 2010 these refineries operated at their lowest levels of between 0 and 30 percent of capacity, and led to the country importing about 85 percent of its fuel needs. By early 2011, operational capacity increased to between 60 and 75 percent but the country still requires product imports to meet demand.

Nigerian Crude Oil Exports by destination 

New refineries have been planned for several years now but lack of financing has caused several delays. As part of the PIB energy sector reforms described below, the government plans to end price subsidies and privatize the refining sector. In the meantime, according to Business Monitor International, NNPC has signed contracts to swap crude for products under yearly contracts with Trafigura, an oil trading company, and Cote d'Ivoire's national refiner SIR.

International Oil Companies

Foreign companies operating in joint ventures (JVs) or production sharing contracts (PSCs) with the Nigerian National Petroleum Corporation (NNPC) include ExxonMobil, Chevron, Total, Eni/Agip, Addax Petroleum (recently acquired by Sinopec of China), ConocoPhillips, Petrobras, StatoilHydro, and others.


Shell has been working in Nigeria since 1936 and currently operates the most nameplate crude oil production capacity, estimated to be between 1.2-1.3 million bbl/d. However, the company has been hardest hit by the instability as much of its production is onshore. Much of Shell's crude oil production capacity is shut-in, some since as far back as early 2006. However, in July 2011, Shell reportedly lifted force majeure on about 300,000 bbl/d of Bonny Light crude oil, increasing volumes of this much sought-after light, sweet blend. The company is also divesting from some of its smaller, onshore holdings.


ExxonMobil operates fields producing approximately 800,000 bbl/d (700,000 bbld/ of crude) in partnership with NNPC. Although most of ExxonMobil's production is offshore, the company has also been forced to shut-in production. In 2008, supply disruptions took place as a result of worker strikes carried out by the Petroleum and Natural Gas Senior Staff Association of Nigeria (PENGASSAN) that shut-in all of ExxonMobil's production for about 10 days in late April/early May of that year.


Chevron operates between 600,000 and 700,000 bbl/d of production capacity, some of which has been shut-in since January 2005 (Escravos Field). Total's smaller share of production has been unaffected in recent years whereas Eni/Agip has had some incidents, specifically at the Brass River terminal that have shut-in varying volumes of production since December of 2006.

Sector Organization

In 1977, Nigeria created NNPC. At that time, NNPC's primary function was to oversee the regulation of the Nigerian oil industry, with secondary responsibilities for upstream and downstream developments. In 1988, the Nigerian government divided the NNPC into 12 subsidiary companies in order to better manage the country's oil industry. The majority of Nigeria's major oil and natural gas projects are funded through JVs, with the NNPC.

Recent Developments

The government has been planning to transform NNPC into a more profit-driven company that can seek out private funds in the market. While these discussions have been underway for many years, a Petroleum Industry Bill (PIB) is currently being debated by the National Assembly. The PIB is designed to reform the entire hydrocarbon sector to increase the government's share of revenue; increase natural gas production; streamline the decision making process by dividing up the different roles of NNPC including the creation of a profit-driven company; privatize NNPC's downstream activities; and promote local content. The Bill would also provide for a greater share of oil revenues to the producing communities and expand the use of natural gas for domestic electricity generation.


Parts of the Bill have recently been approved as stand alone laws (see below) while the different agencies and roles of the new National Oil Company and the NNPC have yet to be fully defined. Differing versions of the PIB are currently being debated, especially around more contentious points such as the renegotiation of contracts with international oil companies, the changes in tax and royalty structures and clauses to ensure that companies use or lose their assets. The ongoing debate has delayed investments in both the oil and natural gas sectors.


As part of the energy sector reform, in April 2010, then acting president (now president) Goodluck Jonathan signed the Nigerian Content Development Bill (NCD) into law. The bill is aimed at increasing the role of Nigerian companies in all aspects of the oil and gas industry. The new law requires that Nigerian companies obtain contracts and win bids so long as the local company is capable, the Nigerian content is higher, and the bid is not more than 10 percent higher than the otherwise winning bid. According to the African Oil and Gas Monitor (Afroil) the NCD applies to all contracts worth over US$1 million and also applies to insurance, banking, and other sectors tied into the oil industry.


Natural Gas

Overview


Nigeria had an estimated 187 trillion cubic feet (Tcf) of proven natural gas reserves as of December 2010 according to the BP Statistical Review of World Energy, which makes Nigeria the ninth largest natural gas reserve holder in the world and the largest in Africa. The majority of the natural gas reserves are located in the Niger Delta and the sector is also impacted by the security and regulatory issues affecting the oil industry.

Nigeria Proven Natural Gas Reserves


In 2009, Nigeria produced about 820 Bcf of marketed natural gas and consumed about 255, mostly for electricity generation where, according to the International Energy Agency (IEA) natural gas accounts for about 60 percent of generated electricity.


Gas Flaring

Because many of Nigeria's oil fields lack the infrastructure to produce and market associated natural gas, it is often flared. According to the National Oceanic and Atmospheric Administration (NOAA), Nigeria flared 536 Bcf natural gas in 2010 – or about a third of gross natural gas produced in 2010 according to NNPC. In 2011, the NNPC claimed that flaring cost Nigeria US $2.5 billion per year in lost revenue.


The government of Nigeria has been working to end natural gas flaring for several years but the deadline to implement the policies and fine oil companies has been repeatedly postponed with the most recent deadline being December 2012, which appears unlikely to be met. In 2009, the Nigerian government developed a Gas Master Plan that promotes new gas-fired power plants to help reduce gas flaring and provide much-needed electricity generation; however, progress is still limited.


Nigeria Natural Gas Flaring 


* U.S. data includes all 50 states


** Saudi Arabia data includes Saudi Neutral Zone


Gas to Liquids (GTL)

A Chevron-operated Escravos Gas to Liquids (GTL) project is currently underway. The project is a joint venture with NNPC and South Africa's Sasol and began in 2008. Escravos GTL has faced multiple delays and cost overruns but is currently scheduled to be operational by 2013.

Exports
Liquefied Natural Gas (LNG)

A significant portion of Nigeria's marketed natural gas is processed into LNG. In 2009, Nigeria exported close to 500 Bcf of LNG. Of this, 13.3 Bcf went to the United States, providing 3 percent of total U.S. LNG imports (2 percent of Nigerian exports). Most of Nigeria's LNG was exported to Europe (66 percent), mainly Spain (31 percent), France (15 percent) and Portugal (13 percent). Other export destinations include Asia (15 percent) and Mexico (16 percent). Nigerian LNG exports were down close to 30 percent from 2008 volumes which can also be attributable to problems in the Niger Delta, specifically problems at the Soku gas processing facility. Available U.S. EIA data indicate that the U.S. imported 41 Bcf of LNG from Nigeria in 2010 representing 10 percent of LNG imports but only about 1 percent of total U.S. natural gas imports.


Nigeria's main natural gas project is the Nigeria Liquefied Natural Gas (NLNG) facility on Bonny Island. Partners including NNPC, Shell, Total, and Agip (Eni) completed the first phase of the facility in September 1999. NLNG currently has six trains and a production capacity of 22 million metric tons per year (1.1 Tcf). A seventh train is under construction but this addition has been delayed until sometime after 2012.


Three additional LNG plants with a total of seven trains were expected to come online after 2012, but their expected startups have been postponed beyond 2016. Plans included OK LNG (4 trains), Brass LNG (2 trains), and Progress LNG (1 train). These are in varying stages of development and investment decisions will depend heavily on security, world LNG markets, and the final outcome of the Petroleum Industry Bill. Availability of natural gas will also depend on Nigerian efforts to expand the use of natural gas for domestic electricity generation – efforts that are included in both the Gas Master Plan and the PIB.

International Pipelines

In addition to LNG, Nigeria began exporting some of its natural gas via the West African Gas Pipeline (WAGP) in 2010. The 420-mile pipeline carries natural gas from Nigeria to Ghana via Togo and Benin. Exports should eventually reach initial capacity of 170 million cubic feet per day (MMcf/d) and plans are underway to expand capacity to as much as 450 MMcf/d and possibly extend the pipeline further west to Cote d'Ivoire.

West African Gas Pipeline 


Nigeria and Algeria continue to discuss the possibility of constructing the Trans-Saharan Gas Pipeline (TSGP). The 2,500-mile pipeline would carry natural gas from oil fields in Nigeria's Delta region to Algeria's Beni Saf export terminal on the Mediterranean. In 2009 the NNPC signed a memorandum of understanding (MoU) with Sonatrach, the Algerian national oil company in order to proceed with plans to develop the pipeline. Several national and international companies have shown interest in the project including Total and Gazprom. Security concerns along the entire pipeline route, increasing costs and ongoing uncertainty in Nigeria will continue to delay this project.

Monday, December 19, 2011

OPEC is raising its target for production



Saudi Arabia won over fellow OPEC members to forge agreement on a new oil production ceiling for the first time in three years, to accommodate increasing output from Libya and Iraq.

Qatar International Petroleum Marketing Co., known as Tasweeq, offered 3 million barrels of Al-Shaheen crude for February loading. Libya’s National Oil Corp. agreed to buy 3 million tons of gasoline next year from four international companies, according to the manager of its supply department.

The following is a weekly summary of Persian Gulf crude and product market news and forthcoming events:
Crude Oil

Crude for January delivery on the New York Mercantile Exchange fell as much as 99 cents to $92.54 a barrel. The contract, which expires tomorrow, fell as low as $92.52 on Dec. 16, the lowest price since Nov. 3. The more actively traded February futures were at $93.79, up 4 cents. Prices are 2.4 percent higher this year after rising 15 percent in 2010.

The Organization of Petroleum Exporting Countries set its output limit at 30 million barrels a day, aligning its target more closely with actual supply and establishing a base-line from which to cut production if the global economy deteriorates further in 2012. Saudi Arabia, OPEC’s biggest producer, boosted output to more than 10 million barrels a day in November.

Iraq plans to start operating the first of four new offshore terminals for tankers, raising its export capacity by 900,000 barrels a day. OPEC’s third-largest crude producer scheduled its next licensing round for drilling rights for March 7-8 in Baghdad.

Russia’s OAO Tatneft (TATN) signed a $1 billion accord with Iran to develop the Persian Gulf nation’s Zagheh oil field. Hindustan Petroleum Corp. (HPCL), India’s third-largest state refiner, plans to import oil from Syria. Iran and Syria are both seeking foreign energy investments and contracts as they come under stricter international economic sanctions.

Tasweeq of Qatar offered 3 million barrels of Al-Shaheen crude for February loading, according to two traders who received a notice from the company and declined to be identified because they aren’t authorized to speak to media.

National Oil Corp., the Libyan state energy company, awarded a tender to sell two shipments of crude for loading in December to Morgan Stanley and China International United Petroleum & Chemical Corp., known as Unipec, three traders who participate in the market said on Dec. 9.Morgan Stanley (MS) bought 600,000 barrels of Mellitah blend for Dec. 28 to Dec. 31, while Unipec bought 1 million barrels of Amna grade for Dec. 26 to Dec. 31, said the traders, who declined to be identified because the information is confidential.
Light Products

The premium of gasoil, or diesel, to Asian marker Dubai crude rose $1.55 to $19.62 a barrel at 12 p.m. Singapore time, according to PVM Oil Associates Ltd., a broker. This crack spread is a measure of processing profit.

Fuel oil’s discount to Dubai crude narrowed 57 cents to $3.76 a barrel, based on PVM data. The difference is the narrowest so far this month. The premium of 180-centistoke fuel oil to 380-centistoke grade, or the viscosity spread, was unchanged after decreasing to $13.75. This means bunker, or marine fuel, moved in tandem with higher-quality fuel oil.

Saudi Basic Industries Corp. (SABIC), the world’s biggest petrochemicals producer, is developing a method to convert crude oil into petrochemicals without passing it through a refinery, said Prince Faisal bin Turki, an adviser to Saudi Arabia’s oil ministry. The country expects to produce 100 million metric tons in 2016, a 250 percent increase from 2006, he said on Dec. 16.

Qatar’s Tasweeq offered to sell cargoes of full-range naphtha for January loading and deodorized field condensate and low-sulfur condensate for February, according to documents e- mailed to potential buyers on Dec. 6. It also offered to sell a gasoline cargo for loading in January, and term supplies of the motor fuel for the first half of next year.

Libya’s National Oil agreed to buy 3 million tons of gasoline next year from four international companies, according to Fathi Rajab, manager of the company’s supply department. National Oil will receive 10 or 11 cargoes monthly, each containing 25,000 tons to 30,000 tons of the fuel, he said, declining to identify the companies

Wednesday, December 14, 2011

A civil lawsuit against Chevron in Brazil



A Brazilian lawsuit that seeks to halt Transocean Ltd. (RIG) andChevron Corp. (CVX) operations after an oil spill would reduce the country’s offshore drilling at a time when it wants to double output in ten years.

Federal prosecutors in Campos, in the oil region of Rio de Janeiro state, are suing both companies for 20 billion reais ($10.6 billion) in environmental and social damages and asked a court to suspend their operations, according to a statement yesterday.

Chevron, based in San Ramon, California, and Transocean, based in Vernier, Switzerland, said they haven’t been notified of the lawsuit and are cooperating with Brazilian authorities.

The case imperils Brazil’s plan to boost crude output because Transocean operates 10 out of the 61 rigs working in the country and it would be hard to replace them in a tight market for oil equipment, said Judson Bailey, an analyst at Jefferies & Co Inc.

Brazilian oil production growth has slowed after the country increased safety requirements following the spill at BP Plc’s Macondo well in the Gulf of Mexico last year.

“The rig market is pretty tight, so if Transocean were banned, the oil companies wouldn’t be happy at all,” Bailey said in a phone interview from Houston. “Chevron and Petrobras can’t get a rig elsewhere, so it messes with the state-owned oil company.”

Chevron, Brazil’s third-largest producer behind state- controlled Petroleo Brasileiro SA (PETR4)and Royal Dutch Shell Plc, will see production wane in Brazil until the government lets it drill again, said Cleveland Jones, an oil specialist and professor at Rio de Janeiro State University.
‘Opening Shot’

Chevron fell 3 percent to $100.53 at the close in New York yesterday. Transocean declined 3.9 percent to $40.19.

Chevron has come under increased scrutiny in Brazil after 3,000 barrels of oil leaked last month from an oil field in deep waters of the Campos Basin. The company underestimated the amount of pressure at an oil deposit it was exploring, and crude leaked from the reservoir for about eight days, George Buck, the head of Chevron for Brazil, said on Nov. 20.

BP has booked more than $40 billion in losses related to the April 2010 blowout of the Macondo well in the Gulf of Mexico. The accident killed 11 workers aboard Transocean’s Deepwater Horizon well and spilled 4.9 million barrels of crude. That’s about $8,163 per barrel spilled, compared to $3.57 million per barrel if the Brazilian fine were to hold.
Still Operating

“Ultimately this is an opening shot, Chevron’s attorneys are probably not at all fazed by this,” said Jones. “The prosecutor’s office will be a positive development for Chevron, because they will ensure that the letter of the law is followed and the letter of the law is reasonable.”

Chevron said in an e-mailed statement that it “responded responsibly to the incident at its Frade Field and has dealt transparently with all Brazilian authorities.” Guy Cantwell, a Transocean spokesman, said the company’s rigs are operating in Brazilian waters and the company continues to cooperate with the government.

Chevron holds a 51.74 percent stake in Frade. Petrobras holds a 30 percent stake, and Frade Japao Petroleo Ltda., a joint venture including Inpex Corp. and Sojitz Corp, holds 18.26 percent. Frade is about 230 miles (370 kilometers) northeast of Rio de Janeiro in the Campos Basin and produced 76,000 barrels a day of oil and natural gas in October.
Criminal Lawsuit

In the next few weeks, prosecutors will probably file a criminal lawsuit against Chevron for alleged environmental crime, said Romulo Sampaio, a law professor at Brazil’s Getulio Vargas Foundation.

“In this case, everything conspires against the company: it’s a foreign company, drilling for oil in Brazilian waters. That may bring about emotional responses,” Sampaio, who coordinates the university’s Environmental Law program, said in a telephone interview.

Prosecutors’ track record in lawsuits against companies involving environmental issues has been at best mixed. Federal prosecutors twice this year sought to halt construction of the Belo Monte hydroelectric dam in the Amazon, and on both occasions federal judges ruled that the project should proceed.

Federal prosecutors in 2009 convinced Brazilian cattle ranchers in Para, the state that has lost the most forestland to illegal logging, to halt Amazon forest destruction and replant trees to avoid an international ban on meat after prosecutors took action.

Brazil’s five largest meatpackers -- JBS SA, the world’s largest beef producer, Marfrig Alimentos SA, Bertin SA, Minerva SA and Frigol Comercial Ltda. -- agreed to stop buying cattle from suppliers that contributed to stripping the Amazon forest.

A lawsuit against Alcoa Inc. is still pending after six years of legal haggling. Federal and state prosecutors sued Alcoa’s Brazilian mining subsidiary in 2005 in an effort to block construction of the Juruti bauxite mine in the state of Para, saying the company had circumvented the law by not applying for a federal permit and instead seeking a license from the state of Para.

Oil production increased at New Zealand Tarakani Basin



New Zealand Energy Corp announced an update on production from its Copper Moki-1 well in New Zealand's Taranaki Basin. The well is free-flowing at an initial rate of approximately 580 barrels of oil per day through an 18/64th inch choke with a gas oil ratio of 970 standard cubic feet per barrel. NZEC has installed surface facilities to accommodate production of up to 1,000 barrels of oil per day.


The Company expects near-term operating netbacks in excess of US$90 per barrel. The oil is sweet and high quality and sells at a premium to the Brent reference price. NZEC anticipates establishing permanent facilities by mid-2012 that can be expanded to handle production from additional wells in the Copper Moki area.


Copper Moki-1 is NZEC's first well in the Taranaki Basin. Copper Moki-1 was completed in August 2011 and tested over a two-day period, during which the well flowed 1,100 barrels of 41.8 API oil per day and 855 thousand cubic feet ("mcf") per day of natural gas on a 28/64th inch choke. NZEC designed an extended production test at a restricted rate to evaluate the reservoir under constant operating conditions and flowed the well for 12 days with average production of 521 barrels of oil and 508 mcf of natural gas per day on a 20/64th inch choke.

New Zealand Oil Production


Following pressure build up, the well commenced production on December 10, 2011. Field production rates are expected to level out at 550 barrels of oil and 535 mcf of natural gas per day. Produced oil is being trucked to the Shell-operated Omata Tank Farm, approximately 45 km north of the Copper Moki well site, and sold to Shell as per an off-take agreement. NZEC is also evaluating options to market its natural gas production, given the close proximity of open-access gas pipelines and significant in-country demand for natural gas.


NZEC is finalizing its multi-well drilling contract for Copper Moki-2 and Copper Moki-3, delineation wells for the Copper Moki pool, and expects to commence drilling of Copper Moki-2 by year-end. The Copper Moki-2 well will be drilled from the same pad as the Copper Moki-1 well to target both the Urenui and Mt. Messenger formations. NZEC will continue to produce Copper Moki-1 as drilling proceeds, and could very quickly bring Copper Moki-2 on-stream using the same production facilities should the well yield oil and natural gas production. The Copper Moki-3 well will be spudded upon completion of Copper Moki-2 and will target multi-zone potential in the Mt. Messenger, Urenui and Moki formations.

Taranaki Basin


he Taranaki Basin offers an excellent opportunity to add substantial reserves and production in an environment of relatively low technical risks with established oil and natural gas infrastructure. NZEC holds and is operator on two large permits, Eltham (100%) and Alton (50%), totalling 615 net square km (152,066 net acres) directly offsetting known production and reserves.


NZEC’s two permits have already yielded 33 prospects or leads and substantial resource estimates of 730 million barrels OOIP and 66.7 million barrels of prospective (recoverable) resources using a conservative 9% recovery factor. NZEC completed an extended production test of its Copper Moki-1 discovery well in November and expects to bring the well on-stream in early December, bringing cash flow to the company and transitioning NZEC from an exploration-stage company to an oil and gas producer. NZEC plans to drill two more Copper Moki delineation wells (Copper Moki-2 and Copper Moki-3) starting in early December, and will continue to produce Copper Moki-1 as exploration proceeds.

Copper Moki Oil Well


The Taranaki is New Zealand’s sole oil and natural gas producing basin, accounting for 100% of the country’s current volumes of approximately 130,000 boe/day (55,000 barrels/day of crude oil and 460 mmcf/day of natural gas). The Taranaki Basin has been producing since 1934 when the first well came on-stream near New Plymouth. Average per-well productivity of approximately 325 boe/d in the Taranaki Basin is many times the North American average. NZEC’s two permits are surrounded by pools currently producing approximately 18,000 boe/d. Prior to NZEC’s involvement, however, only two historical exploration wells had been drilled in what is now the Eltham Permit area.


This region offers immense opportunities for further exploration and development. There have been only 400 wells drilled since 1950, virtually all of which relied on older technology (vertical wells completed without hydraulic fracturing) and conventional exploration ideas (sandstone reservoirs with structural traps). Until recently, substantial prospective lands remained unallocated and unexplored.


Geologically, the Taranaki Basin’s sediments extend from shallow burial at approximately 200 metres all the way to the deep basement at more than 6,000 metres. Hydrocarbon source rocks are believed to be deeply buried Paleocene and Cretaceous coaly rocks and shales. Drilling targets are primarily sandstones with some carbonates, with four horizons dominating to date: the Kapuni Group, which can be as deep as 4,000 metres and accounts for the majority of current basin production, and the generally shallower Moki, Mount Messenger and Urenui at depths of 1,000 to 3,000 metres.


NZEC sees the Taranaki Basin as an excellent opportunity both to drill unexploited prospects in known reservoir types and to maximize per-well results through the application of modern technology. This includes using modern seismic reprocessing and interpretation to identify the stratigraphic-structural traps that were overlooked in the past. In addition, the recent advent of horizontal drilling by other companies in the area has yielded excellent results, with initial productivity approximately 2.5 times the average rate for comparable vertical wells.

Tuesday, December 13, 2011

Recovery time for Iraq and Libya



Libya’s crude production will return to pre-conflict levels of 1.6 million barrels a day by 2014, International Energy Agency said.

“The recovery in Libyan output has exceeded expectations so far in 2011,” the Paris-based adviser said today in its monthly oil market report. Libyan output dropped to 45,000 barrels a day in August, according to Bloomberg estimates.

Oil Export by destination Libya

Oil production Libya


Libya, holder of Africa’s biggest oil reserves, will increase daily output to 1.6 million barrels by the end of 2012, Nuri Berruien, chairman of state-run National Oil Corp., said last month.

Iraq will account for about 80 percent of the forecast increase in OPEC’s crude-oil production capacity by 2016, according to theInternational Energy Agency.

The 12-member group of oil-exporting nations will be capable of producing 38.1 million barrels a day in five years, up from 35.8 million in 2010, the IEA said in a report today. Iraq’s crude output is predicted to increase by 1.87 million barrels a day to 4.36 million.

Oil Production Iraq

Oil Export by destination Iraq


The Paris-based agency lifted its Iraq outlook by 335,000 barrels a day from its June estimate, citing “steady progress at the country’s 12 joint venture projects.” The IEA also warned that the withdrawal of U.S. troops this year may jeopardize stability.

The recovery in Libya’s output also exceeded expectations in 2011, with output forecast to rise to pre-war levels of 1.6 million barrels a day by 2014, the agency said. Libya pumped 500,000 barrels a day in November, from a low of 45,000 barrels in the midst of the rebellion against former leader Muammar Qaddafi.

Thursday, December 8, 2011

OPEC Oil Export Revenues


Based on projections from the EIA August 2011 database, members of the Organization of the Petroleum Exporting Countries (OPEC) could earn $1,011 billion of net oil export revenues in 2011 and $1,105 billion in 2012. Last year, OPEC earned $778 billion in net oil export revenues, a 35 percent increase from 2009. Saudi Arabia earned the largest share of these earnings, $225 billion, representing 29 percent of total OPEC revenues. On a per-capita basis, OPEC net oil export earnings reached $2,074 in 2010.

Methodology

This report includes estimates of OPEC net oil export revenues. For each country, estimates of oil production and consumption from the latest version of the STEO are used to derive net oil exports. We assume that these exports are sold at prevailing spot prices. For countries that export several different crude varieties, we assume that the proportion of total net oil exports represented by each variety is equal to the proportion of the total domestic production represented by that variety; in other words, if we assume that Arab Medium represents 20 percent of total oil production in Saudi Arabia, then we assume that Arab Medium represents 20 percent of total net oil exports from Saudi Arabia.





OPEC Net Oil Export Revenues

CountryNominal (Billion $)Real (Billion 2005$)
201020112012Jan-Jul 2011201020112012Jan-Jul 2011
Algeria$53- -- -$41$47- -- -$35
Angola$56- -- -$38$49- -- -$33
Ecuador$8- -- -$6$7- -- -$5
Iran$73- -- -$56$64- -- -$48
Iraq$50- -- -$40$44- -- -$35
Kuwait$60- -- -$48$53- -- -$41
Libya$44- -- -$9$39- -- -$8
Nigeria$65- -- -$52$57- -- -$45
Qatar$37- -- -$33$33- -- -$28
Saudi Arabia$225- -- -$180$198- -- -$155
UAE$67- -- -$57$59- -- -$49
Venezuela$41- -- -$34$36- -- -$29
OPEC$778$1,011$1,105$594$685$863$926$510
View entire series (1975-2012): nominal or real
OPECPerCapita Net Oil Export Revenues

CountryNominal ($)Real (2005$)
201020112012Jan-Jul 2011201020112012Jan-Jul 2011
Algeria$1,540- -- -$1,169$1,356- -- -$1,003
Angola$4,249- -- -$2,879$3,741- -- -$2,470
Ecuador$542- -- -$413$477- -- -$354
Iran$1,085- -- -$826$955- -- -$709
Iraq$1,686- -- -$1,335$1,484- -- -$1,145
Kuwait$21,416- -- -$16,702$18,848- -- -$14,327
Libya$6,837- -- -$1,339$6,017- -- -$1,158
Nigeria$450- -- -$354$396- -- -$303
Qatar$38,281- -- -$33,400$33,685- -- -$28,651
Saudi Arabia$7,685- -- -$6,081$6,763- -- -$5,216
UAE$13,508- -- -$11,120$11,888- -- -$9,538
Venezuela$1,498- -- -$1,244$1,318- -- -$1,067
OPEC$2,074$2,644$2,837$1,560$1,825$2,257$2,378$1,339