Friday, July 29, 2011

US car makers agreed on 54.5mpg of fuel consumption efficiency

Major carmakers have agreed new fuel efficiency standards proposed by the Obama administration in an effort to end the dominance of gas guzzlers.

They have agreed that by 2025, cars and light trucks sold in the US will drive on average 54.5 miles per gallon (mpg) of fuel, compared with 27 mpg today.

The White House said the measures would reduce imports of foreign oil and consumers' petrol costs.Environmental groups said the deal would reduce air pollution.The impact of the fuel economy standards will depend on the details of the regulations. Previous fuel economy regulations have made exceptions for light trucks and SUVs, which helped lead to a boom in sales of these vehicles, cancelling out much of the reduction in fuel consumption provided by more efficient cars.

President Barack Obama was joined by carmaker executives as he made the announcement in Washington on Friday.He said it would lower the country's oil use by 2.2m barrels a day over the next 15 years and save US consumers almost $2tn (£1.2tn) in fuel costs.

"This agreement on fuel standards represents the single most important step we've ever taken as a nation to reduce our dependence on foreign oil," Mr Obama said.

By the time the standards take effect, the government expects gas-electric hybrids to make up about half of new vehicles.It comes two years after Mr Obama arranged an $80bn bailout of the US car industry.

With the industry in the doldrums amid the economic downturn and fierce competition from foreign automakers in 2009, Mr Obama helped shepherd a taxpayer-financed bankruptcy reorganisation of General Motors and Chrysler, two major US carmakers.

That left them without the political capital to oppose Mr Obama's proposed fuel efficiency regulations, analysts said.

Tuesday, July 26, 2011

Brazil Energy Report

Brazil is the ninth largest energy consumer in the world and the third largest in the Western Hemisphere, behind the United States and Canada. Total primary energy consumption in Brazil has increased by close to a third in the last decade, due to sustained economic growth. In addition, Brazil has made great strides in increasing its total energy production, particularly oil and ethanol. Increasing domestic oil production has been a long-term goal of the Brazilian government, and recent discoveries of large offshore, pre-salt oil deposits could transform Brazil into one of the largest oil producers in the world.

Total Brazilian energy consumption grew to 10.6 quadrillion British thermal units (BTU) in 2008. The largest share of Brazil's total energy consumption comes from oil and other liquids (50 percent, including ethanol), followed by hydroelectricity (34 percent) and natural gas (8 percent). Natural gas is currently a small share of total energy consumption, but attempts to diversify electricity generation from hydropower to gas-fired power plants could cause natural gas consumption to grow in the coming years.

Oil and Other Liquids


According to the Oil and Gas Journal (OGJ), Brazil has 12.9 billion barrels of proven oil reserves in 2011, the second-largest in South America after Venezuela. The offshore Campos and Santos Basins, located off of the country's southeast coast, hold the vast majority of Brazil's proven reserves. In 2010, Brazil produced 2.7 million barrels per day (bbl/d) of liquids, of which 75 percent was crude oil. Brazil's oil production has risen steadily in recent years, with the country's oil production in 2010 about 150,000 bbl/d (6 percent) higher than in 2009.

Based on its January 2011 Short-Term Energy Outlook, EIA forecasts Brazilian oil production to reach 2.9 million bbl/d in 2011 and 3.0 million bbl/d in 2012. Brazil's liquids consumption averaged 2.52 million bbl/d in 2009. As a result of this rising oil production and flat consumption growth, Brazil became a net oil exporter in 2009.

Exploration and Production
Most Brazilian oil is produced in the southeastern region of the country in Rio de Janeiro and Espírito Santo states. More than 90 percent Brazil's oil production is offshore in very deep water and consists of mostly heavy grades. Five fields in the Campos Basin (Marlim, Marlim Sul, Marlim Leste, Roncador, and Barracuda) account for more than half of Brazil's crude oil production. These Petrobras-operated fields each produce between 100,000 and 400,000 bbl/d. International oil companies also play a role in Brazilian production. The Shell-operated Parque de Conchas project and the Chevron-operated Frade project are expected to achieve production levels of 100,000 bbl/d and 68,000 bbl/d, respectively.

Recent offshore exploration efforts in Brazil have yielded massive discoveries of pre-salt oil fields.


In 2009, Brazil's liquids production surpassed its liquids consumption. In the January 2011 Short-Term Energy Outlook, EIA projects that Brazil will continue to be a net exporter through the end of 2012. As pre-salt discoveries boost Brazilian production in the medium and long term, crude oil exports should steadily increase. However, this export growth could be moderated by increases in domestic consumption driven by rapid economic growth. Brazil still imports some light crude oil to meet the needs of its refinery fleet.

Sector Organization

State-controlled Petrobras is the dominant participant in Brazil's oil sector, holding important positions in up-, mid-, and downstream activities. The company held a monopoly on oil-related activities in the country until 1997, when the government opened the sector to competition. Royal Dutch Shell was the first foreign crude oil producer in the country, and it is now joined by Chevron, Repsol, Anadarko, Devon, Statoil and BG Group. Private competition in the sector is not just from foreign companies: Brazilian oil company OGX, which is staffed largely with former Petrobras employees, expects to start producing in the Campos Basin sometime in 2011.

The principal government agency charged with monitoring the oil sector is the National Petroleum Agency (ANP), which is responsible for issuing exploration and production licenses and ensuring compliance with relevant regulations. Recent legislation concerning pre-salt exploration and production has changed the operating environment somewhat. A full discussion of this can be found in the pre-saltsection.


According to OGJ, Brazil has 1.9 million bbl/d of crude oil refining capacity spread amongst 13 refineries. Petrobras operates 11 facilities, the largest being the 360,000-bbl/d Paulinia refinery in Sao Paulo. The refining capacity in Brazil is relatively simple, meaning that the country must export some of its heavy crude oil production and import light crude oil – domestic crude constituted 79 percent of total domestic refinery feedstock in 2009. To meet burgeoning domestic demand, Petrobras plans to increase its Brazilian refining capacity to more than 3.0 million bbl/d by 2020. Under the company's 2010-2014 business plan, Petrobras will build five additional refineries to meet this goal. These facilities will be designed to process heavier grades of crude, increasing the share of Brazilian oil processed in these refineries to 91 percent.


Brazil is the second largest producer of ethanol in the world behind the United States. In 2009, Brazil produced 450,000 bbl/d of ethanol, down from 467,000 in 2008. Despite this decline, the Brazilian Sugarcane Industry Association (UNICA) expects production to rise again following a successful 2010-2011 harvest season.

Although Brazil is the world's leading ethanol exporter, most of this added production will go to meet increasing domestic demand. All gasoline in Brazil contains ethanol, with blending levels varying from 20-25 percent. Additionally, over half of all cars in the country are of the flex-fuel variety, meaning that they can run on 100 percent ethanol or an ethanol-gasoline mixture.

Pre-Salt Oil

A consortium of Petrobras, BG Group, and Petrogal discovered the Tupi field in 2007, which contains substantial reserves that occur in a pre-salt zone 18,000 feet below the ocean surface under a thick layer of salt. Following Tupi, numerous additional pre-salt finds were announced in the Santos Basin, such as Iracema, Carioca, Iara, Libra, Franco and Guara. Additional pre-salt discoveries were also announced in the Campos and Espirito Santo Basins. Estimates for the total pre-salt resources vary. Some analysts place total extent of pre-salt recoverable oil and natural gas reserves at more than 50 billion barrels of oil equivalent.

In December, 2010 Petrobras submitted a declaration of commerciality to the ANP for the Tupi and Iracema fields, which renamed the fields Lula and Cernambi, respectively. The total recoverable reserve estimate for these fields is 8.3 billon barrels of oil equivalent (boe) (6.5 billion boe for Tupi and 1.8 billion for Iracema).

Petrobras plans to develop its major pre-salt assets in three discrete phases: extended well tests, pilot projects, then large-scale production through multiple, duplicate floating production, storage, and offloading (FPSO) facilities. The Tupi Pilot project, which has a production capacity of 100,000 bbl/d, began in October 2010. In its 2010-2014 business plan, Petrobras plans to invest $33 billion in pre-salt exploration and production activities to achieve an oil production target of close to 4 million bbl/d by 2020. More than a quarter of this target is to come from pre-salt oil.

Brazil's pre-salt announcements immediately transformed the nature and focus of Brazil's oil sector, and the potential impact of the discoveries upon world oil markets is vast. However, considerable challenges must still be overcome in order to bring these reserves to fruition. The difficulty of accessing reserves, considering both the large depths and pressures involved with pre-salt oil production, represent technical hurdles that must be overcome. Further, the scale of the proposed expansion in production will also stretch Petrobras' exploration and production resources and Brazil's infrastructure.

Regulatory Reforms

The Brazilian government released the proposed regulatory framework for the pre-salt reserves in August 2009. The framework consists of four pieces of legislation. The first two laws were signed into law in July of 2010. The first law creates a new agency, Petrosal, to administer new pre-salt production. The second allowed the government to capitalize Petrobras by granting the company 5 billion bbl of unlicensed pre-salt oil reserves in exchange for larger ownership share.

The other two bills, establishing a new development fund to manage government revenues from pre-salt oil and laying out a new production sharing agreement (PSA) system for pre-salt reserves, passed through Brazil's congress in December of 2010. In contrast to the earlier concession-based framework, Petrobras will be the sole operator of each PSA and would hold a minimum 30 percent stake in all pre-salt projects. Some analysts fear that the new system's increased level of state involvement and drain on Petrobras' resources could slow the development of these resources.

Debate on the issue of royalty distribution among Brazilian states is expected to continue well into 2011. Once a final agreement is in place, Brazil is expected to hold an eleventh auction round for exploration blocks in 2011.

Natural Gas

OGJ reported that Brazil had 12.9 trillion cubic feet (Tcf) of proven natural gas reserves in 2011. The Campos, Espírito Santo, and Santos Basins hold the majority of reserves, but sizable reserves also exist in the interior of the country. Despite Brazil's substantial natural gas reserves, natural gas production has grown slowly in recent years, mainly due to a lack of domestic transportation capacity and low domestic prices. In 2009, Brazil produced 363 billion cubic feet (Bcf) of natural gas – the majority of this production was associated with oil.

Natural gas consumption is a small part of the country's overall energy mix, constituting only 8 percent of total energy consumption in 2008. Brazil experienced a demand spike from 701 Bcf to 835 Bcf in 2008, as a result of low water levels in hydroelectricity reservoirs increased demand for thermal power generation and high oil prices made natural gas an attractive substitute fuel in the industrial sector. In 2009 demand contracted to 661 Bcf.

Sector Organization

Petrobras plays a dominant role in Brazil's entire natural gas supply chain. In addition to controlling the vast majority of the country's natural gas reserves, the company is responsible for most domestic Brazilian gas production and for gas imports from Bolivia (see below). Further, Petrobras controls the national transmission network and it holds a stake in 18 of Brazil's 27 state-owned natural gas distribution companies. However, Brazil passed a new Natural Gas Law in 2009 which created a separate regulatory framework for natural gas. This law is expected to facilitate private investment in the sector.

Exploration and Production

The largest share of Brazil's natural gas production occurs in offshore fields in the Campos Basin in Rio de Janeiro state. Most onshore production occurs in Amazonas and Bahia states and is mostly for local consumption due to the shortage of transportation infrastructure.

In order to meet rising demand and decrease reliance on imports, Petrobras plans to bring several new natural gas projects online over the coming years. The largest is the Mexilhao project, which contains estimated total reserves of 8 Tcf. Current plans call for production to come online in March 2011 at 154 Bcf per year, eventually rising to 193 Bcf per year.

As discussed in the oil section of this report, recent announcements about discoveries in Brazil's offshore pre-salt have generated much excitement. Along with their potential to significantly increase oil production in the country, the pre-salt areas are estimated to contain sizable natural gas reserves as well. According to Petrobras, Tupi alone could contain 5-7 Tcf of recoverable natural gas, which if proven, could increase Brazil's total natural gas reserves by 50 percent.


Petrobras operates Brazil's domestic natural gas transport system. The network has over 4,000 miles of natural gas pipelines, mostly in the southeast and northeast parts of the country. For years these systems were not interconnected, which has hindered the development of domestic production and consumption. However, in March 2010 the Southeast Northeast Interconnection Gas Pipeline (GASENE) linked these two markets for the first time. This 870-mile pipeline, which runs from Rio de Janeiro to Bahia, is the longest ever built in Brazil. GASENE is intended to offset supply shortfalls in the northeast caused by declining local production with southeastern offshore supply.

The other major natural gas market in Brazil is the Amazon region. In 2009, Petrobras completed construction of the Urucu pipeline linking Urucu to Manaus, the capital of Amazonas state. This project is expected to facilitate the development of the Amazon's considerable, and largely untapped, natural gas reserves.

Brazil imported 298 Bcf of natural gas in 2009, a 24 percent drop from 2008. The decline in Brazilian overall natural gas demand, coupled with policy choices aimed at reducing imports, led to this decline. The country currently receives imports by pipeline from Bolivia and liquefied natural gas (LNG) imports from Trinidad and Tobago and Nigeria. Import growth in the future is expected to be met more with LNG than with conventional pipeline imports.

Imports from Bolivia

Brazil imports natural gas from Bolivia via the Gasbol pipeline, which links Santa Cruz, Bolivia to Porto Alegre, Brazil, via Sao Paulo. The 2,000-mile Gasbol has a maximum capacity of 1.1 Bcf per day (Bcf/d). In early 2009, Brazil announced that it would reduce imports from Bolivia from 1.1 Bcf/d to 0.7 Bcf/d. According to ANP, Brazilian imports of Bolivian gas have since declined by 27 percent. However, Boliviastill accounted for 96 percent of Brazil's total natural gas imports.

Liquefied Natural Gas

Brazil has two liquefied natural gas (LNG) regasification terminals, both installed in the last two years: the Pecem terminal in the northeast, and the Guanabara Bay terminal in the southeast. Both facilities are floating regasification and storage units (FRSU) operated by Golar LNG, with a combined sendout capacity of 740 MMcf/d. The Pecem received its first LNG cargo from Trinidad and Tobago in July 2008, while the Guanabara Bay terminal came online in May 2009. According to ANP, Brazil received 15 Bcf of natural gas in the form of LNG in 2009, mostly from Trinidad and Tobago.


Brazil had 104 gigawatts of installed generating capacity in 2008, with the single largest share being hydroelectric capacity. In 2009, the country generated 461 billion kilowatthours (Bkwh) of electric power, while consuming 421 Bkwh. Hydropower accounted for 84 percent of this generation, with smaller amounts coming from conventional thermal, nuclear, and other renewable sources.

Sector Organization

The government plays a substantial role in the Brazilian electricity sector. Until the 1990s, the state controlled the electricity sector almost completely. Brazil initiated an electricity sector privatization process in 1996. However, when drier-than-average weather led to severe energy shortages in 2000 and 2001, the process stalled. While around 65 percent of electricity distribution companies were privatized, the bulk of Brazil's major generation assets remain under government control. Electrobras, a state-owned holding company, constitutes the dominant player in the electricity market. The government also owns almost the entire electricity transmission network.

In 2004, the Brazilian government implemented a new Power Sector Model. This hybrid approach to state involvement splits the sector into regulated and unregulated markets for different producers and consumers. This allows for both public and private investment in new generation and distribution projects. Under the plan, however, Electrobras was formally excluded from privatization efforts.


Brazil generated 387 Bkwh of hydroelectric power in 2009. Many of Brazil's hydropower generating facilities are located far away from the main demand centers, resulting in high transmission and distribution losses. Brazil's largest hydroelectric generation asset is the Itaipu facility on the Parana River, which Brazil maintains with Paraguay. According to Itaipu Binacional, the facility generated 94.7 Bkwh of electricity in 2008. Although Brazilian planners aspire to diversify away from hydropower to mitigate supply shortage risks brought about by dry weather, new hydro projects continue to move forward. Most notable among these projects is the Belo Monte plant in the Amazon basin which, upon completion, will be the third largest hydroelectric plant in the world behind China's Three Gorges Dam and Itaipu.

Thermal Generation

Thermal generating sources provided only a small part of Brazil's electricity supply, contributing about 13 percent in 2009. According to Brazil's Ministry of Energy and Mines, the largest contributor to Brazil's thermal power generation in 2009 was biomass (38 percent). This figure includes “autoproducer” electricity, which is generated at ethanol plants by burning sugar cane byproducts. This source could increase in significance if transmission and distribution hurdles are overcome.

Other thermal generation sources play a small role in Brazil's electricity mix. Petroleum use in the electricity sector has been declining for some time. Despite efforts to increase natural gas use in the power generation fuel mix, natural gas share of thermal generation remains small due its high cost relative to hydroelectricity. However, EIA projects that natural gas use in the electricity sector will increase as Brazil expands and diversifies its natural gas supplies.

Nuclear Power

Brazil has two nuclear power plants, the 630-megawatt (MW) Angra-1 and the 1,350-MW Angra-2. State-owned Eletronuclear, a subsidiary of Eletrobras, operates both plants. Construction of a third plant, the 1,350-MW Angra-3, started in 1986, but was never finished. In 2008, construction began again, with completion slated for 2015. According to industry sources, Eletronuclear plans to build at least four new nuclear power plants (in addition to Angra-3) by 2030, in order to meet expected growth in Brazilian electricity demand.

Friday, July 22, 2011

Increasing domestic demand threatens Saudi oil exports

Saudi Arabia's oil exports look to decline sharply over the long term as the Middle Eastern country’s own domestic demand is expected to consume more of its production.

“The country's domestic consumption of energy, especially oil, at very cheap prices, is…likely to continue to rise rapidly, sharply reducing the amount of oil available for export,” said a report by Riyadh-based Jadwa Investment.The report noted that the sharp drop in oil exports constitutes “a major challenge” to Saudi Arabia given its heavy reliance on oil exports in the absence of other major sources of income.

The report notes that Saudi Arabia's oil exports had already plunged from 7.5 million b/d in 2005 and could fall even further to 6.3 million b/d in 2015.An expected high growth in domestic consumption could further depress exports to 6 million b/d in 2020 and to only 4.9 million b/d in 2030, it said.

Jadwa said oil consumption is rising rapidly in Saudi Arabia, with domestic oil use averaging 2.4 million b/d in 2010, up from 1.9 million b/d in 2007 and 1.6 million b/d in 2003."The pace of consumption growth has picked up in recent years, from an annual average of 4.8% between 2000-04 to 5.9% between 2005-09,” the report said."If we assume that only transportation and industrial use of oil grows at that rate, while oil used for power generation stays constant, then domestic oil consumption in 2030 grows to 5.5 million b/d,” the report said.

“Recall this would be a portion of our base case view of total production of 11.5 million b/d, leaving the country with only around 6 million b/d for export."

The Jadwa outlook is largely in line with earlier remarks by Saudi oil officials, who as a result, have been advocating the use of nuclear power and other forms of renewable energy within the kingdom.

"The total domestic energy demand is expected to rise from about 3.4 million boe/d in 2009 to 8.3 million boe/d in 2028, or a growth of 250%," Saudi Aramco Pres. and Chief Executive Khalid A. Al-Falih said last year.At that rate, he said, "the oil availability for exports is likely to decline to less than 7 million b/d by 2028, a fall of 3 million b/d while the global demand for our oil will continue to rise" (OGJ Online, Jan. 31, 2011).

Thursday, July 21, 2011

US gasoline price hit 3.68$

July 2011 U.S. Retail Gasoline Prices, 
 Dollars per gallon, including all taxes
Change from
Change from
week ago
year ago

Maine, New Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Pennsylvania, Delaware, Maryland, D.C, Virginia, West Virginia, North Carolina, South Carolina, Georgia, Florida3.5673.6473.7060.0591.058
Maine, New Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island3.7213.7673.8260.0591.101
New York, New Jersey, Pennsylvania, Delaware, Maryland, D.C.3.6343.6873.7380.0511.041
Virginia, West Virginia, North Carolina, South Carolina, Georgia, Florida3.4713.5813.6470.0661.058
Ohio, Kentucky, Tennessee, Michigan, Indiana, Illinois, Wisconsin, Minnesota, Iowa, Missouri, North Dakota, South Dakota, Nebraska, Kansas, Oklahoma3.5953.6703.6930.0230.992
Alabama, Mississippi, Arkansas, Louisiana, Texas, New Mexico3.4093.5023.5680.0661.013
Montana, Wyoming, Colorado, Idaho, Utah3.5193.5093.5210.0120.772
Washington, Oregon, California, Nevada, Arizona, Alaska, Hawaii3.7453.7303.7460.0160.684
Washington, Oregon, Nevada, Arizona, Alaska, Hawaii3.6603.6473.6520.0050.709

New York State3.8073.8393.9000.0611.047

Los Angeles3.8463.8343.8440.0100.697
New York City3.7203.7623.8080.0461.055
San Francisco3.8163.8043.8310.0270.659

U.S. Retail Gasoline Prices - 2 1/2 years
The average price for regular grade gasoline rose from the prior week by 4.1 cents according to the EIA—at $3.682 for the week ending July 18. Regular grade prices continued to be below annual averages of 2008 (see second chart below), when gasoline prices reached a high of $4.062 in 2008 when adjusted to May 2011 dollars. Prices remained higher than a year ago, with regular gasoline up 96.0 cents or 35.3 percent from 52 weeks ago (see first chart to the right). For the week ending July 18, crude oil costs were up 79.9 cents from a year ago, and were 4.6 cents per gallon higher than the May average of 2011 on a monthly basis. Compared with a year ago, the share for manufacturing and marketing gasoline this week was 14.3 cents higher or 26.3 percent.

Wednesday, July 20, 2011

US Oil Stripper Well Count and share of production

Oil Stripper Well Count and share

A stripper well or marginal well is an oil or gas well that is nearing the end of its economically useful life. In the United States of America a "stripper" gas well is defined by the Interstate Oil and Gas Compact Commission as one that produces 60,000 cubic feet (1,700 m3) or less of gas per day at its maximum flow rate; the Internal Revenue Service, for tax purposes, uses a threshold of 75,000 cubic feet (2,100 m3) per day. Oil wells are generally classified as stripper wells when they produce ten barrels per day or less for any twelve month period.

Marginal-volume stripper wells make an important contribution to U.S. oil and natural gas production. Today's article looks at oil stripper wells; tomorrow's Today in Energy will focus on natural gas stripper wells.

Individual oil stripper wells produce no more than 15 barrels of oil equivalent per day over a twelve-month period (some wells also produce natural gas), yet collectively account for a significant portion the Nation's oil production—over 16% in 2009. Their sheer number (over 300,000) allows oil stripper wells to make a major contribution to U.S. oil production.

The number of oil stripper wells has remained roughly constant since 1994. Their share of total oil production stayed fairly level through 2003. Since 2003, their production share has increased; while over the same period, the oil stripper well count rose less, increasing about 5%.

In the period of 2003 through 2009, this disproportionate increase in production share was more significant due not only to an overall increase in production from oil stripper wells, but also largely as a result of flagging production from non-stripper oil wells. During that period, the non-stripper oil well count fell by about 3% and production from non-stripper oil wells dropped nearly 15%.

Tuesday, July 19, 2011

Kuwait Oil and Gas Report

Kuwait is a member of the Organization of Petroleum Exporting Countries (OPEC), exporting the fourth largest volume of oil among the group in 2010. At the same time, Kuwait's economy is one heavily dependent on petroleum export revenues, which account for half of its overall gross domestic product (GDP), 95 percent of total export earnings, and 95 percent of government revenues. Kuwait has an active sovereign-wealth fund, the Kuwait Investment Authority, which oversees all state expenditures and international investments. Kuwait also allocates 10 percent of its state revenues into the Reserve Fund for Future Generations (RFFG), for the day when oil income starts to decline.

Article 21 of the Kuwaiti constitution specifically allocates all natural resources and revenue they generate to the state. However, the Foreign Direct Capital Investment Law passed by the National Assembly in March 2001, has facilitated some foreign investment and development in those sectors, causing significant controversy in Kuwait.

According to Oil & Gas Journal, as of January 2011, Kuwait's territorial boundaries contained an estimated 101.5 billion barrels (bbl) of proven oil reserves, roughly 7 percent of the world total. Additional reserves are held in the Partitioned Neutral Zone (aka Divided Zone), which Kuwait shares on a 50-50 basis with Saudi Arabia. The Neutral Zone holds an additional 5 billion barrels of proven reserves, bringing Kuwait's total oil reserves to 104 billion barrels. These reserve estimates have been openly questioned by some analysts and a number of Kuwaiti parliamentarians, with some putting reserves as low as 48 billion barrels.

Sector Organization

The government of Kuwait owns and controls all development of the oil sector. The Supreme Petroleum Council (SPC) oversees Kuwait's oil sector and sets oil policy. The SPC is headed by the Prime Minister. The rest of the council is made up of six ministers and six representatives from the private sector, all of whom serve three-year terms, and are selected by the emir. The Ministry of Petroleum supervises all aspects of policy implementation in the upstream and downstream portions of both the oil and natural gas sectors.

The Kuwait Petroleum Corporation (KPC) manages domestic and foreign oil investments. Kuwait Oil Company (KOC), the upstream subsidiary of KPC, was taken over by the Kuwaiti government in 1975 and manages all upstream development in the oil and gas sectors. Various subsidiaries of KPC control Kuwait's oil sector. The Kuwait National Petroleum Company (KNPC) controls the downstream sector, while the Petrochemical Industries Company (PIC) is in charge of the petrochemical sector. Export operations are overseen by both KNPC and the Kuwait Oil Tanker Company (KOTC). Foreign interests of KPC are handled by the Kuwait Foreign Petroleum Exploration Company (Kufpec), and international upstream development and downstream operations are controlled by Kuwait Petroleum International (KPI). Finally, Kuwait Energy Company (KEC) is a privately-held company that has developed a number of foreign interests over the past decade, including interests in Yemen, Egypt, Russia, Pakistan, and Oman.

The Partitioned Neutral Zone (PNZ) has its own managing companies, separated by onshore and offshore activities. The onshore sector was developed by American Independent Oil Company (Aminoil), which was nationalized in 1977. Getty Oil, which would eventually be subsumed by Chevron, was brought in to develop onshore PNZ fields Wafra, South Umm Gudair and Humma. Chevron remains a participant along with KPC, although management of all KPC PNZ interests have been transferred to the Kuwait Gulf Oil Company (KGOC). Offshore, a Japanese company, the Arabian Oil Company (AOC) discovered Khafji, Hout, Lulu and Dorra oil fields in the 1960s. The concessions with Saudi Arabia and Kuwait expired in 2000 and 2002, respectively, neither of which was renewed. KGOC was established in 2002 to oversee the offshore operations for KPC. Subsequently, KGOC, along with Aramco Gulf Operations Company (AOGC), set up a joint operating company, Al-Khafji Joint Operations Company (KJO), manages offshore PNZ production.

Source: Kuwait Oil Company (KOC)

Exploration and Production

In 2010, Kuwait's total oil production was approximately 2.5 million barrels per day (bbl/d), including its share of approximately 250,000 bbl/d production from the PNZ. Of the country's 2010 production, approximately 2.3 million bbl/d was crude and 200,000 bbl/d was non-crude liquids. Slightly over half of Kuwaiti crude production in 2010 came from the southeast of the country, largely from the Burgan field; production from the north has increased to approximately 800,000 bbl/d. As a member of OPEC, Kuwait's total production is constrained by the organization's production targets, which in 2010 meant the country maintained about 320,000 bbl/d of spare crude oil production capacity. In early 2011, as one of the few OPEC members with spare capacity, Kuwait has increased oil production to compensate for the loss of Libyan supplies.

KPC has initiated a $90 billion expansion plan encompassing both the upstream and the downstream. Included in this are plans to upgrade Kuwait's production and export infrastructure and its tanker fleet, expand exploration, and build downstream facilities, both domestically and abroad, which is expected to boost oil production capacity to 4 million bbl/d by 2020.

Largely as a result of political impasse, exploration in Kuwait has not made significant inroads in the recent past. Discoveries of lighter crudes in the center of the country have been successful, but progress has not moved beyond the planning stages. In 1984, a discovery in South Maqwa was made, revealing light crude of API 35°-40° grade, and after drilling began at Kra'a al-Mara in 1990, significant volumes of 49° API crude was found. Negotiations were begun with Exxon, but the conditions to move this project to full development have not been reached. Many expect Kuwait to classify such a high grade of crude as condensate so as to avoid its qualification for OPEC targets.

Another successful discovery was made in 2005-6 in the Sabriya and Umm Niqa areas, in the north of the country, which added an estimated 20-25 billion barrels of reserves, although of a much heavier, sour quality. In February 2010, Shell signed an Enhanced Technical Service Agreement (ETSA) to exploit these new discoveries however progress has been slow in boosting production. KOC is also having trouble developing the Lower Fars reservoir of al-Ratqa field. KOC initially negotiated with ExxonMobil, Shell, and Total to develop this field however KOC subsequently abandoned plans for a joint project development. KPC also signed a memorandum of understanding (MOU) in July 2010 with Japan Oil, Gas and Metals National Corporation (JOGMEC) to assess the feasibility of injection of carbon dioxide as a potential enhanced oil recovery (EOR) technique.

Much of Kuwait's reserves and production are concentrated in a few mature oil fields discovered in the 1930s and 1950s. The Greater Burgan oil field, which comprises the Burgan, Magwa, and Ahmadi reservoirs, makes up the dominant portion of both reserves and production. Burgan is widely considered the world's second largest oil field, surpassed only by Saudi Arabia's Ghawar field. Greater Burgan was discovered in 1938, but did not become fully developed until after World War II. Burgan has been producing consistently ever since. Generally, production from Burgan comprises medium to light crudes, with API gravities in the 28°-36° range. Although Burgan's recent production of between 1.1 and 1.3 million barrels per day (bbl/d) accounted for around half of Kuwait's total production, Burgan has a production capacity of 1.75 million bbl/d. KOC is seeking to boost Burgan's capacity largely from the Wara reservoir. A tender for foreign firms to install water injection facilities should be issued by the end of 2011, with the goal of increasing production from Wara to 350,000 bbl/d by 2014, from its current 80,000 bbl/d.

Other production centers in the south of the country include Umm Gudair, Minagish, and Abduliyah. Umm Gudair and Minagish produce a variety of crude oil grades, but largely fall in the medium range, with gravities of 22°-34° API. In January 2003, water injection began at Minagish to enhance oil recovery and offset natural declines in production. An exploration well drilled in 2009 discovered light crude and associated natural gas at Mutriba oil field to the west of Rudhatain. As much as 80,000 bbl/d are expected from this field, with plans for production coming on-stream by 2014.

Northern Kuwait holds the majority of Kuwait's larger fields other than Greater Burgan. Kuwait's second largest source of crude production is from the northern Raudhatain field, with a capacity of 350,000-400,000 bbl/d. Sabriya is adjacent to Raudhatain and adds another 100,000 bbl/d. The frontier fields of al-Ratqa, the southern extension of Iraq's Rumaila structure and the smaller Abdali field were both obtained after the new border was forged in 1993 following the end of the Persian Gulf War. They add another 75,000 bbl/d of additional production capacity. In August 2010, British Petrofac signed a deal with KOC to boost production capacity at Raudhatain and neighboring Sabriyah fields. In the same month, Kuwaiti and Iraqi officials agreed in principle to mutually develop shared oil fields, as well as to allow an international oil company (IOC) to aid in such projects. It was not clear how the respective state-run oil companies would be involved and to what degree.

Project Kuwait

A focal point of Kuwait's aspirations to attain a production capacity of 4 million bbl/d is Project Kuwait. Proposed in 1998, Project Kuwait was an asserted effort to create proper incentives for attracting foreign participation. The contract structure that resulted was challenged as unconstitutional and the National Assembly has impeded progress of Project Kuwait for a number of years. Kuwait's constitution bars foreign ownership of the country's natural resources, which precludes the product-sharing agreements (PSAs) that normally provide proper incentive for investment. In order to allow IOC involvement, an “incentivized buy-back contract" (IBBC) arrangement was created, which neither involves production sharing nor concessions. The structure of the IBBC agreements allows the Kuwaiti government to retain full ownership of oil reserves, control over oil production levels, and strategic management of the ventures. Foreign firms are to be paid a "per barrel" fee, along with allowances for capital recovery and incentive fees for increasing reserves. In May 2007, the Kuwaiti ruling family conceded the responsibility to approve each related IBBC for Project Kuwait to parliament, which has caused further delays. Additionally, more performance-based incentives have been introduced in an enhanced technical service agreement (ETSA) structure, although only one has been awarded so far.

Project Kuwait aims to increase the country's oil production capacity from four northern oil fields Raudhatain, Sabriya, al-Ratqa, and Abdali. This serves as a pivotal component to increase production capacity to 3.5 million bbl/d by 2015, and 4 million bbl/d by 2020, which KOC admits will require the help of IOCs. Some agreements, such as the ETSA with Royal Dutch Shell forged in February 2010 and continued negotiations with other IOCs over EOR developments have enhanced prospects for foreign participation, yet no other final agreements have been made. Production from the north has seen a boost over 2010, approaching 800,000 bbl/d with the installation of an 120,000 bbl/d early production facility at the Sabriya field. Heavy oil is also a major long-term component of Project Kuwait, providing a projected 60,000 bbl/d by 2015 and 270,000 bbl/d by 2020, although this is much lower than the original forecast production of 750,000 bbl/d. Estimated heavy oil reserves of approximately 13 billion barrels are located primarily in the north of Kuwait, with other reserves concentrated in the Neutral Zone.

An unconventional source of potential production over the medium-term will be related to the clean-up of the large pools of crude that have remained since the retreat of the Iraqi army during the First Gulf War. The KOC has announced plans to finish the tender process by the end of 2011 for firms that will aid in soil remediation, which could result in significant crude volumes. The entire operation will take years and cost roughly $3.5 billion, paid for by the UN reparations fund, however the first phase involves only three sites. The Iraqi army set more than 800 wells ablaze and estimates indicate that as much as 5 million bbl/d were lost over the nine months it took to extinguish the fires. The lakes number in the thousands and were created by the seawater used to put out the fires. There is also the potential that the clean-up could facilitate further exploration and production, as the lakes restrict access to producing areas and known reserves.

Partitioned Neutral Zone

The Partitioned Neutral Zone (PNZ) was established in 1922 to settle a territorial dispute between Kuwait and Saudi Arabia. The PNZ encompasses a 6,200 square-mile area and contains an estimated 5 billion barrels of oil and 1 trillion cubic feet (Tcf) of natural gas. Oil production capacity in the PNZ is currently about 600,000 barrels per day, all of which is divided equally between Saudi Arabia and Kuwait.

Onshore production in the PNZ centers on the Wafra oil field. In production since 1954, Wafra is the largest of the PNZ's onshore fields with approximately 3.4 billion in proven and probable reserves. Wafra has related production facilities and gathering centers with South Umm Gudair and South Fuwaris. Onshore production in the PNZ has a capacity of 240,000 bbl/d, but is in decline. A full field steam injection project is being considered, but a final investment decision is not expected before 2013.

The production capacity of offshore fields in the PNZ is 350,000 bbl/d, with almost 90 percent coming from Khafji. Offshore production is about four times as expensive in the PNZ as in the rest of Kuwait. Production offshore originates from Khafji, an extension of Saudi Arabia's Safaniyah (the world's largest offshore field); Hout, which is also an extension of Safaniyah; and Dorra, an extension of Iran's Arash and shared with KSA. Dorra is not currently under production, pending resolution of boundary demarcation negotiations and plans for joint development between Kuwait and Iran, which is facing increasing political impediments.

Exports and Consumption

Kuwaiti exports of total oil amounted to some 1.8 million bbl/d, of which 1.7 million bbl/d was crude oil. Most Kuwaiti crude oil is sold on term contracts. Kuwait's crude exports are all a single blend of all its crude types. The largest proportion is the lighter Burgan crude, which is blended with heavier, more sour crude from northern fields, as well as marginal amounts from Minagish and Umm Gudair. Kuwait's single export blend ("Kuwait Export") has a specific gravity of 31.4°API (a typical medium Mideast crude), and is generally considered sour, with 2.52 percent sulfur content. In 2010, the Asia-Pacific region received approximately 1.4 million bbl/d, while exports to the United States totaled 196,000 bbl/d, and Western Europe received around 100,000 bbl/d.

With the majority of its export volumes headed to Asian markets, the most significant benchmark for Kuwaiti exports is the Oman-Dubai, to which it sells at a slight discount. As of the beginning of 2010, the price of Kuwaiti crude oil for American customers was tied to the Argus Sour Crude Index (ASCI), a weighted average of various North American medium, sour crudes. European buyers purchase from a benchmark linked between a Brent weighted-average and Saudi Arab Medium.

Mina al-Ahmadi is the country's main port for the export of crude oil. Kuwait also has operational oil export terminals at Mina Abdullah, Shuaiba, and at Mina Saud, otherwise known as Mina al-Zour. To handle increased production generated by Iraq and the northern fields, a new terminal is planned for construction on Bubiyan Island.

Kuwait consumes only a small portion of its total petroleum production. The country consumed a total of 325,000 bbl/d in 2010, leaving the vast majority of its production available for exports. While domestic consumption has been steadily increasing, partly as a result of increased petroleum-fired electricity consumption, about 87 percent was slated for exports last year and forecasts indicate that this trend will continue in the near term.


Oil & Gas Journalputs nameplate refining capacity in Kuwait at 936,000 bbl/d. This production capacity is derived from three refinery complexes: al-Ahmadi, Abdullah, and al-Shuaiba. All of the refineries are located in close proximity to the coastline, about 30 miles south of Kuwait City and are owned and operated byKuwait National Petroleum Company (KNPC). Kuwait is a large exporter of refined products, as refining capacity is about three times the level of domestic demand for petroleum. The largest refinery is Mina al-Ahmadi, which was built in 1949, and has a capacity of 466,000 bbl/d. Mina Abdullah and al-Shuaiba have a nameplate capacity 270,000 bbl/d and 200,000 bbl/d, respectively.

Kuwait Petroleum International (KPI), also known as Q8, manages KPC's refining and marketing operations internationally. Its operations include approximately 4,000 retail stations across Belgium, Spain, Sweden, Luxembourg, and Italy. KPI has interests in two refineries, owning an 80,000 bbl/d refinery in Rotterdam, Netherlands and a 50:50 joint venture with Italian major ENI in the 240,000 bbl/d capacity refinery in Milazzo, Italy.

Kuwait is seeking to cultivate downstream interests in markets with high potential demand growth, the Asian market in particular, specifically China, Vietnam, and Indonesia. In China's Guangdong Province, KPC is negotiating a refinery and petrochemical joint venture with China's Sinopec, with a remaining stake to be allocated to a third company in the near future. The plant will feature a 300,000 bbl/d capacity refinery, which will also have an ethylene steam cracker with the capacity to produce 1 million tons per year (mtpa). In March 2011, China's National Development and Reform Commission (NDRC) gave final approval to the project, making Kuwait the second Arab oil producer behind Saudi Arabia to have a major downstream facility in China. Sinopec has announced a planned commission date of 2014, however analysts predict a much longer timeframe, with a likely start-up in 2018-2019. Kuwait aims to increase its exports from 200,000 bbl/d to 500,000 bbl/d with the conclusion of the refinery.

Kuwait Petroleum International (KPI) joined with PetroVietnam and Japanese Idemitsu in April 2008 to construct a 200,000 bbl/d refinery in Nhi Son, Vietnam. In November 2010, the Vietnamese government approved the project, which should be completed by 2014. KPI currently holds a 35 percent stake, which will be reduced for PetroVietnam to take a majority stake once the refinery comes on-line. Indonesian officials have also announced a possible $8-9 billion, 300,000 bbl/d refinery with KPC on the island of Java.

Clean Fuels Project/Al-Zour

Two long delayed projects comprise Kuwait's ambitious downstream plans: the Clean Fuels Project and the al-Zour refining facility. These two projects have an estimated combined cost of over $31 billion. The Clean Fuels Project (CFP) is the project under which Kuwait's existing refineries will be upgraded. Due to the rapid rise of domestic demand, including expansions in the petrochemical sector, and increased demand for higher quality products in Kuwait's traditional export markets, these two projects are progressing with increased urgency. In June 2011, the Supreme Petroleum Council (SPC) approved both projects.

The two elements of the general overhaul of Kuwait's refining sector seek to build the al-Zour refinery, retiring old units and installing new components, while shutting down the al-Shuaiba refinery altogether. A crude distillation unit (CDU) will be taken out of commission at the Mina al-Ahmadi, while Mina Abdullah will lose a number of components, but its overall capacity will increase by 184,000 bbl/d.

The al-Zour refinery was originally tendered in 2008, but political opposition led to the cancellation of the bid round. This forced KPC to compensate those companies who had spent resources preparing their bids, placing the entire project on hold. This is not the first project to be halted as a result of political gridlock, as the collapse of K-Dow, a $17 billion joint venture between KPC subsidiary Petrochemical Industries Company (PIC) and Dow Chemical Company, in December 2008 attests. This results in significant costs to KPC, as they needed to compensate Dow for the capital it had already deployed in preparations and acquisitions.

Natural Gas
According to Oil & Gas Journal, as of January 2011, Kuwait had an estimated 63 trillion cubic feet (Tcf) of proven natural gas reserves. Kuwait's reserves are not significant and this has spurred an extensive drive in natural gas exploration. Vast discoveries of non-associated gas in the north of the country attracted interest from international oil companies (IOCs) however unattractive contract structures and political uncertainty remain principal impediments to any rapid expansion of both reserves and production. Additionally, new discoveries are geologically more complex, being mainly tight and sour gas deposits which require more sophisticated and costly development.

Sector Organization

As in the oil sector, all of the natural gas resources are owned by the Kuwait Petroleum Corporation (KPC). The Kuwaiti constitution prohibits any use of production-sharing agreements (PSAs) that allow for an equity stake by an IOC in development projects. Therefore, Kuwait is using technical service agreements (TSAs) in order to bring in IOCs to develop more difficult projects. In February 2010, Shell signed an enhanced technical service agreement (ETSA) for the 2006 natural gas discoveries in the north, known as the Jurassic fields, amounting to 35 Tcf of reserves in place, the nature of which are too sour for local firms to develop.

Exploration and Production

In 2010, Kuwait produced 1.17 billion cubic feet per day (Bcf/d) of natural gas. This volume was an increase of around 8 percent compared with 2009. Given the predominance of associated natural gas in Kuwaiti production, domestic natural gas supplies decreased as a result of lower OPEC crude production quotas. Kuwait increasingly requires supplies of natural gas for the generation of electricity, water desalination, and petrochemicals, as well as increased use for enhanced oil recovery (EOR) techniques to boost oil production. Kuwait is shifting its exploration drive in order to focus on natural gas discoveries to mitigate imports of liquefied natural gas (LNG) and decrease the proportion of oil used domestically. KOC has announced a production target of 4 Bcf/d by 2030, about four times the current production level.

Associated natural gas production makes up the vast majority of Kuwait's overall production. In 2010, approximately 1 billion cubic feet per day (Bcf/d) was produced from associated gas, while non-associated gas production amounted to only 150-200 million cubic feet per day (MMcf/d). Production of non-associated natural gas from the north is seen as the most promising future source of natural gas production growth. Given Kuwait's fiscal and political climate, not much progress has been made in exploring the mainly offshore prospects, leaving Kuwait to focus on its natural gas discoveries in the north.

The Jurassic non-associated gas field was discovered in 2006, with an estimated 35 Tcf of reserves. This project has been described as the most difficult in the world, for its geologic composition and the technical complexities that this presents. A first phase envisioned 175 MMcf/d and 50,000 bbl/d of condensate by 2008 however it seems to have reached a production plateau at 140 MMcf/d. The second phase is being constructed by Kharufi National and Saipem with a projected capacity of 500 MMcf/d due to come online by 2013. Original development plans of Jurassic forecast production of 600 MMcf/d by 2012 and 1 Bcf/d and 350,000 bbl/d of light crude or condensate, the classification of which is still undetermined, by 2015, although industry experts see this as unlikely, if not impossible at this point. Shell has been developing the Jurassic project through its 2010 ETSA.

The other prospect for non-associated natural gas production is the Dorra gas field offshore PNZ. This field is shared by Kuwait, Saudi Arabia, and Iran, which calls the field Arash. Kuwait and Saudi Arabia have already announced plans to begin production at Dorra by 2017, providing an additional 500-800 MMcf/d. Iran, in response, has indicated that it will develop its own side of the field in the near future. Political tensions between the Gulf States and Iran are at their highest in recent history, which will preclude any near-term settlement of mutual development.

Kuwait is also expanding its gas processing infrastructure in order to meet rising domestic demand. Daelim of South Korea is currently constructing Kuwait's fourth gas processing plant, its largest to date at 800 MMcf/d. This unit will be on the site of the Ahmadi refinery and give Kuwait a gas processing capacity of 2.3 Bcf/d by 2013. A fifth train, the same size as the fourth is also in the planning stages, taking potential capacity over 3 Bcf/d. However, neither the current production plans nor the expansion of processing facilities is expected to meet the growing levels of domestic demand.

Consumption and Imports

In 2010, Kuwait consumed approximately 529 Bcf of natural gas, which is equal to 1.45 Bcf/d. Since 2008, Kuwait has consumed more natural gas than it has produced. This has compounded the problem of electricity outages by making the availability of feedstock precarious. As such, Kuwait has had to resort to imports of liquefied natural gas (LNG) to make up for this supply gap. In 2010, Kuwait imported 270 MMcf/d of LNG, largely from regional neighbors, Yemen and Oman. Re-exports of LNG from Qatar via Abu Dhabi were also necessary, as Saudi Arabia disallowed a pipeline directly linking Kuwait with Qatar three years ago. Kuwait's electricity demand, the generation of which is fueled increasingly by natural gas, has outpaced natural gas production during the summer months, resulting in the shutdown of refinery and petrochemical operations to meet the increased demand of electricity.

In June 2009, Kuwait signed a deal with Shell to import LNG, receiving the first cargo in August 2009. KPC made another deal with international energy trading firm, Vitol, in April 2010, which will supply Kuwait with LNG cargoes through 2013. Kuwait takes delivery of the LNG at the Persian Gulf's first regasification terminal, Mina al-Ahmadi GasPort. The regasification capacity of al-Ahmadi is approximately 500MMcf/d of LNG. A study is expected to be completed by the end of 2011 to explore the need for permanent LNG import facilities and expanding the current LNG import volumes.

Kuwait has also recently exhibited interest in supplies from the impending natural gas project in Southern Iraq. Royal Dutch Shell, Mitsubishi and Iraqi state-owned Southern Oil Company (SOC) are developing infrastructure to gather associated natural gas from Iraq's southern oil fields. A potential pipeline from Iran's South Pars gas fields has been placed on hold, as political considerations make the project less likely. These prospective imports would still not mitigate the need for continued LNG imports.

Kuwait has an installed electric generation capacity of 11,300 MW, which was slightly above peak demand of 10,900 MW in the summer of 2010. Electric generation comes from Kuwait's five existing power plants: Doha East, Doha West, Shuaiba North, al-Subiya, and al-Zour South. In 2009, Kuwait had overall electric generation of 49.8 terawatt hours (Twh). Kuwait has come to embody the difficulties facing the region's electricity networks, with rapid demand growth causing rolling blackouts at times of peak energy demand. Slow implementation of developments plans, as well as a lack of feedstock, has served to create shortages in electricity supply during the hot summer months. Formerly having one of the largest reserve margins in the region, Kuwait is perpetually in a state of electricity supply shortage. In the past decade, the development of Kuwait's electric sector has stalled due to political factors, despite consistent annual demand growth of 8 percent. Only one power plant was commissioned during that time, bringing a comfortable reserve margin to a shortage beginning in 2006.

Given the rapidly increaseing demand over the past decade, the Kuwaiti government has unveiled an extensive development plan for the electric grid. Kuwait plans to add 10,000 MW, nearly doubling its generation capacity by 2015. In order to achieve this, Kuwait will employ public-private projects (PPPs), as well as independent water and power projects (IWPP). Kuwait is the last Gulf country to incorporate the private sector into the development of its electric sector. This has caused some political resistance, as it potentially leaves operation with foreign firms, in a build-own-operate (BOO) structure, rather than the former engineering, procurement and construction (EPC) model that left operation in the hands of the government. The first evidence of private sector participation is the expansion of the al-Subiya complex built by General Electric (GE) and Hyundai Heavy Industries of South Korea. The GE power plant at al-Subiya is a 2000MW power plant that has an initial capacity of 1300MW, which started operations in June 2011. It will add needed reserve capacity to the electric system, going into the peak demand months of summer. The power plant is a combined-cycle facility, using natural gas primarily, with fuel oil as a back-up. It will be the first new power plant to become operational in over 20 years and it will reach its nameplate capacity of 2000MW by mid-2012. Five other power plants are in various stages of development to achieve the forecast capacity and bring an adequate buffer between peak demand and generation capacity.

Nuclear Power

In the long-term, Kuwait is planning to utilize nuclear energy. In March 2009, Kuwait announced its intention to establish a nuclear commission. Subsequently, in January 2010, the head of the National Nuclear Energy Committee announced a 20-year cooperative deal with the the French Atomic Energy Commission in the development of nuclear power in Kuwait. Kuwait announced that it is considering four nuclear power plants, set to become operational by 2022 and has agreed to allow International Atomic Energy Agency (IAEA) inspectors into any future nuclear sites. An additional nuclear agreement with the United States has been discussed, but not finalized.

Gulf Cooperation Council (GCC) Grid

The Gulf Cooperation Council (GCC), of which Kuwait is a member, faces rapidly increasing demand growth in electricity. As a result, the six Gulf countries of UAE, Kuwait, Qatar, Bahrain, Saudi Arabia, and Oman began a region-wide power grid. Phase III of the GCC Grid will connect the Northern System – Kuwait, Bahrain, Saudi Arabia, Qatar – to the Southern System – UAE, and Oman by the end of 2011. Some analysts believe the GCC Grid has the potential to expand into North Africa and eventually link with Europe's power grids. Kuwait has already had to utilize regional electricity imports from the Northern System, as it has been plagued by electricity supply shortfalls. The integrated power grids will reduce power outages in the short-term and increase power exchange across seasons and time zones