Wednesday, February 29, 2012

Chevron will invest $1.9 Billion in Congo Republic Oil Field

A new "significant discovery" of oil in the shared deepwater zone between Congo Brazzaville and Angola's Cabinda exclave was announced today. The deepwater block in the Gulf of Guinea is operated by the oil multinational ChevronTexaco and smaller Angolan and Congolese companies.

ChevronTexaco today announced what the company called "a significant discovery at the Lianzi-1 exploration well in the deepwater area between the republics of Angola and Congo." This is the first major oil discovery in the promising offshore area that recently was announced as a shared zone between the governments of Congo Brazzaville and Angola. The deepwater zone is localised offshore Angola's troubled Cabinda exclave.

Cabinda south block

The Lianzi-1 exploration well had been drilled at a water depth of 909 meters, according to the oil company. The well there had encountered two oil bearing reservoirs and "a drill stem test of one of the intervals flowed at a rate of more than 5,000 barrels of oil per day," the ChevronTexaco statement said.

The well at Lianzi-1 had found geological strata similar to operating deepwater fields in Angola; the Landana discovery of 1998 and the Tombua discovery of 2001. This, according to the oil companies, proves the excellent chances of making even more discoveries in the deepwater zone offshore Congo and Angola. 

Lianzi development zone

George Kirkland, President of ChevronTexaco Congo, today commented that "the Lianzi discovery is yet another addition to a number of excellent deepwater prospects in the region. These discoveries will provide a series of developments in the future and fuel production growth. This discovery speaks to the success of our strategy of focusing our exploration program on core, high-impact opportunities," he added.

Jim Blackwell, managing director of ChevronTexaco's Cabinda Gulf Oil Company commented that the company had long been "optimistic about the exploration opportunities" in the shared zone and "this find helps to justify that optimism. The next step will be to complete several geologic and engineering studies to fully assess the field's size, reserves potential and possible development options," said Mr Blackwell.

The shared unit covers the portions of "14K" - a major Angolan (Cabinda) deepwater prospect - and the "A-IMI" prospect, lying within the limits of the Congo's Haute Mer permit. It incorporates the area along the maritime border between the two countries. 

Angola Lianzi Map

The Angolan-Congolese shared zone of 696 square kilometres is a result of protocol and participation agreements signed by Angola and Congo Brazzaville in September 2001 and March 2002, respectively. The two countries agreed to share revenues equally (50/50) for each block; both Congo's Haute Mer and Angola's Block14.

The establishment of the joint zone marked a major advance in Brazzaville-Luanda relations, both economically and regarding the conflict in Cabinda, which is now coming towards a solution. The good neighbourly relations were today also emphasised by a state visit of Congo Brazzaville's Minister Henri Jombo, who was received by Angolan President José Eduardo dos Santos in Luanda today.

ChevronTexaco, through its affiliate companies, holds a total interest in the discovery of 30.5 percent and Chevron Overseas Congo is the operator of the unit. Other participants in the two blocks include Angola's Sonangol (10.0 percent), Congo's SNPC (7.5 percent), Total (35.5 percent), ENI (10.0 percent), GALP Exploracão (4.5 percent) and Energy Africa (2.0 percent).

Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco (FST) area. Net production from these operations in 2010 averaged 161,000 barrels of oil-equivalent per day.

The company operates the 39.2 percent-owned Block 0, which averaged 116,000 barrels per day of net liquids production in 2010. The Block 0 concession extends through 2030.

Development of the Mafumeira Field in Block 0 continued in 2010. A development drilling program was completed in the northern section and achieved maximum total crude oil and condensate production of 57,000 barrels per day in fourth quarter 2010. FEED started in January 2010 on Mafumeira Sul, a project to develop the southern portion of the Mafumeira Field. A final investment decision is expected in fourth quarter 2011. Maximum total production from Mafumeira Sul is expected to be 110,000 barrels of crude oil and 10,000 barrels of LPG per day. At year-end 2010, no proved reserves had been recognized for the Mafumeira Sul project.

Chevron Corp. (CVX), the second-largest U.S. oil producer, plans to invest $1.9 billion in its Lianzi oil field in Congo Republic, according to the nation’s Economy and Planning Ministry.

Lianzi is situated on the maritime border with Angola. The ministry commented in a statement distributed in the capital, Brazzaville, today.

Tuesday, February 28, 2012

Japan January Liquefied Natural Gas Imports rose to a record

Japan’s liquefied natural gas imports rose to a record in January after the Fukushima nuclear disaster led to the shutdown of most of the country’s atomic reactors, causing utilities to use more fossil fuels.

The nation’s LNG imports climbed 28.2 percent from a year earlier to 8.15 million metric tons, according to a preliminary report released today by the Ministry of Finance.

Power utilities increased thermal power generation by 28.5 percent in the month, according to data compiled by the Federation of Electric Power Companies of Japan. The average operating rate of nuclear power plants in January was 10.3 percent, it said.

Japan Electricity Generated and Purchased in January 2012

The country’s crude-oil imports fell 2.1 percent to 18.83 million kiloliters (118 million barrels) in the month, the finance ministry said in the report.
The following table shows Japan’s imports for January:
                                         Year-on-Year Change
Crude oil             18.832                         -2.1%
Gasoline               1.993                        -17.5%
LNG                     8.150                         28.2%
LPG                     0.996                        -14.4%
Coal                   16.837                          7.8%
 (Thermal Coal)   10.029                          7.9%

(Crude oil and gasoline are in millions of kiloliters. LNG, LPG and coal are in millions of tons.)

Monday, February 27, 2012

World's largest petroleum consumer: Asia

World Petroleum Consumption 2010

Asia surpassed North America as the largest petroleum-consuming region in 2008. Asian demand surged nearly 15 million barrels per day from 1980 to 2010, an increase of 146%. North America's petroleum consumption increased 16% between 1980 and 2010. Global petroleum consumption increased 36%, nearly 23 million barrels per day, during the period.
Together, the Middle Eastern, Central & South American, and African share of total global oil demand grew from 11% in 1980 to 20% in 2010 (see chart below). European demand for petroleum decreased 5% from 1980 to 2010, while consumption in the Former Soviet Union fell 55% in the same period.

World Petroleum Consumption graph 1980 2010

Friday, February 24, 2012

Yemen Energy Report

Yemen is a relatively small oil and natural gas producer. However, it is important to the global oil trade because of its strategic location at the tip of the Arabian peninsula on the Bab el-Mandab, one of the world's most important shipping lanes, through which an estimated 3.5 million barrels of oil passed daily in 2010. Disruption to shipping in the Bab el-Mandab could prevent tankers in the Persian Gulf and the Gulf of Aden from reaching the Suez Canal/Sumed pipeline complex, requiring a costly diversion around the southern tip of Africa to reach western markets.

In recent years, the region has seen rising piracy off the Somali coast, in the Gulf of Aden and southern Red Sea, reaching into the Indian Ocean. Security concerns in Yemen involving militant groups have deterred investment in recent years, with numerous attacks on energy infrastructure, particularly oil pipelines, slowing production and increasing costs.Yemen's economy is heavily dependent on hydrocarbons, which accounted for 30 percent of GDP, nearly 75 percent of government revenues, and over 90 percent of foreign exchange earnings in 2010. As oil revenues decline, the government's ability to provide basic services has been weakening. A political crisis occurred in 2011, inspired by similar public demonstrations in Tunisia and Egypt.

 Yemen Map


According to the Oil & Gas Journal, Yemen had proven crude oil reserves of 3 billion barrels as of January 1, 2012. Yemen's oil reserves and production are located in five main geographical areas: Jannah and Iyad in central Yemen, Marib and Jawf in the north, and Shabwa and Masila in the south. All production comes from two sedimentary basins, Marib-Shabwa and Sayun-Masila, out of a total of 12 basins believed to hold reserves. Yemen's oil reserves are generally light and sweet (low in sulfur content) at API gravities ranging from 28 degrees to 48 degrees, with the highest quality crude coming from the Marib-Jawf fields.

Sector Organization

Yemen's General Corporation for Oil, Gas and Mineral Resources is a loose affiliation of several state-owned subsidiaries including: Yemen Oil Company (YOC), Yemen Refining Company (YRC), Petroleum Exploration and Production Authority (PEPA), Yemen Gas Company (YGC), Oil Products Distribution Company, General Department of Crude Oil Marketing, and Safer E&P Operations Company (Safer). General Corporation for Oil, Gas and Mineral Resources is responsible for managing industry contracts and relations with operators and partners, as well as the government's share of crude exports.

All branches report to the Ministry of Oil and Mineral Resources, which is responsible for oil policy. The oil sector is open to private company investment on a production-sharing basis with YOC. Contracts with foreign oil companies, however, require parliamentary approval.

Safer, Yemen's leading national oil company, was formed in 2005 to take over Marib Block 18 when Hunt Oil and ExxonMobil's license expired and the parliament vetoed its extension. Nexen's contract for the Masila oil field expired December 2011 and the contract was taken over by newly-created state-owned PetroMasila, which plans to maximize government revenues from the field.

Production and Exploration

In 2011, Yemen's total oil production averaged about 170,000 barrels per day (bbl/d), down from 259,000 bbl/d estimated for 2010. Production has been declining steadily since reaching a peak of 440,000 bbl/d in 2001 due to a lack of sufficient new investment in exploration and inadequate maintenance of facilities.

In 2011, anti-government strikes, attacks on pipelines, and the evacuation of foreign staff combined to reduce annual production to below 200,000 bbl/d. In March, the main crude oil export pipeline from the Marib and Shabwa fields to the Ras Isa terminal was blown up and remained offline until mid-July. In May, oil exports were reported by the Centre for Global Energy Studies as being less than 70 percent of their normal level. Further attacks on the pipeline occurred and by January 2012, Yemen was reliant on crude and product imports as its main refinery was shut in November.

Yemen has twelve main producing blocks, operated by nine international oil companies. Production at Norwegian DNO International's Block 47 began in 2011, despite the security situation in the country. In 2010, thirty-two blocks were under exploration by 16 oil companies in partnership with Yemen Oil Company. Exploration saw relative success in 2010, with discoveries announced at several blocks.

Despite interest from a large number of companies during an initial licensing round for offshore fields in late 2007 and 2008, domestic security uncertainty and the escalation of piracy in the Gulf of Aden derailed exploration of Yemen's offshore areas. The most recent bidding round was held in October 2010, at the third conference for oil and gas, where 10 oil blocks both on and off shore were put up for bidding. However, the government awarded three new blocks in 2010: Block 48 was awarded to DNO International, Block 85 to Total SA, and Block 86 to Austria's OMV.

Yeman oil production and consumption 1991-2011

Consumption and Exports

Yemen had total oil exports of 103,000 bbl/d and total domestic consumption of 157,000 bbl/d in 2010, according to EIA estimates. Asian markets account for the majority of Yemen's oil exports. With growing domestic consumption and decreasing production, net exports are on a declining trend. Yemen imports some refined products; in 2008, the most recent data available, gross imports of refined products were estimated at 62,000 bbl/d, mainly distillate and residual oils, while 18,000 bbl/d of products were exported.

Pipelines and Export Terminals

Yemen has a 662-mile integrated network of oil pipelines to transport oil from three major central production facilities to five oil export terminals: Aden, Ras Isa, Hodeidah, Bir Ali, and Ash Shihr. The pipelines have been the target of recurring attacks, which curtailed the flow of oil production and exports in 2011.

The 270-mile Marib to Ras Isa pipeline has throughput capacity of 400,000 bbl/d and transports oil from the Marib basin to the Ras Isa offshore export terminal on the Red Sea, Yemen's main crude export point. Ras Isa terminal is operated by Safer and handles most of the company's Marib light crude production. This pipeline was blown up several times in 2011, disrupting throughput.

The 90-mile Masila to Ash Shihr pipeline has capacity of 300,000 bbl/d and runs from Masila and East Al Hajr fields to the export terminal at Ash Shihr on the Gulf of Aden. The Ash Shihr terminal (also called al Mukallah), which is operated by Nexen, has upwards of 3.5 million barrels of storage capacity.

The 130-mile, 135,000-bbl/d Shabwa to Bir Ali pipeline transports crude oil from the Shabwa region to the Bir Ali terminal on the Gulf of Aden. The ports of Aden and Hodeidah handle refined products exported onto smaller tankers.


According to the Oil & Gas Journal, on January 1, 2012, Yemen had a total crude oil refining capacity of 140,000 bbl/d from two aging refineries: the 130,000 bbl/d Aden refinery, built in 1954 and operated by Aden Refinery Company, and the 10,000 bbl/d Marib refinery, built in 1986 and operated by the Yemen Refinery Company. The Aden refinery was shut in May and again in November 2011 due to continuing attacks on connecting crude pipelines, causing products shortages in local markets, and making Yemen reliant on crude and products imports, mainly from neighboring Saudi Arabia.

Natural Gas

According to the Oil & Gas Journal, as of January 1, 2012, Yemen had 16.9 trillion cubic feet (Tcf) of proven natural gas reserves. Most of Yemen's natural gas reserves are associated gas concentrated in the Marib-Jawf oil fields, which contain 10 Tcf of proven natural gas reserves. Success in developing the liquefied natural gas (LNG) sector is likely to increase interest in further natural gas exploration and production. LNG revenues partially offset declining oil export revenues.

Exploration and Production

In 2010, Yemen produced an estimated 1,153 billion cubic feet (Bcf) of gross natural gas, of which 890 Bcf was reinjected to provide enhanced oil recovery and 245 Bcf was marketed, including 194 Bcf exported as LNG.

Natural gas production began in Yemen in 1993. After rising to 727 Bcf in 2005, production declined to 533 Bcf by 2008, but in 2009 production jumped to almost double its 2008 level. Prior to 2009, Yemen produced only associated gas, reinjecting practically all of it to provide enhanced oil production. A long-term LNG sales contract with Korea Gas Corporation was signed in 2005, providing the impetus and the investment needed to begin development of the country's natural gas reserves. Contracts were also signed with GDF Suez and Total. All three contracts run for 20 years.

The Yemeni government's plans for increased domestic use of its natural gas reserves include the transition of power generation from diesel fuel oil to natural gas. Some of the independent energy firms exploring for oil have found associated pockets of natural gas along with new oil discoveries. Reportedly, all new production sharing agreements (PSAs) with foreign companies now include a clause that mandates contractors to invest in Yemen's natural gas infrastructure.

Yemen's Natural Gas Production and Consumption 1993-2010

Liquefied Natural Gas (LNG)

According to Cedigaz estimates, Yemen exported a total of 194 Bcf of LNG in 2010. The principal buyers were South Korea (38 percent), the United States (20 percent), and China (13 percent). According to Reuters, Yemen was able to meet all contractual commitments in 2011, despite the mid-October sabotage to the pipeline supplying the LNG facility.

The Yemen LNG project at the port of Balhaf on the Gulf of Aden became commercially operational in October 2009. At a cost of $4.5 billion, Yemen LNG is the largest industrial project in the country. French company Total holds a 39.6 percent stake in the project, followed by Hunt Oil at 17.2 percent, Yemen Gas Company at 16.7 percent, and 3 South Korean companies - SK Gas at 9.55 percent, KoGas at 6 percent, and Hyundai at 5.88 percent - while other Yemeni investors make up the balance. The Balhaf LNG processing plant, which is operated by Total, added a second train in April 2010, increasing total capacity to 326 Bcf. Balhaf receives natural gas from Block 18 in the Marib-Jawf Basin via a 200-mile, 900-thousand cubic feet per day capacity pipeline. Block 18 is operated by state-run Safer Company, which has earmarked 10 Tcf of natural gas reserves for the LNG project. Yemen LNG has four tankers, with a total capacity of 13 million cubic feet.

Wednesday, February 22, 2012

Gabon Energy Report

Gabon is an established oil producing country in West Africa and has enjoyed decades of economic growth and political stability in comparison to other countries in the region. Oil production undergirds Gabon’s economy, accounting for 45 percent of gross domestic product (GDP) and 60 percent of government revenue, according to the World Bank. 

Gabon Map

Aging oil fields are placing pressure on the Gabonese government to increase economic diversification efforts, as oil output has declined by about 34 percent since its peak in 1997. As a result, Gabon has dropped from being the third largest oil producer in sub-Saharan Africa to the sixth after: Nigeria, Angola, Sudan, Equatorial Guinea, and Congo (Brazzaville).

TOP Oil Producing sub saharan africa-countries 1995-2010

Gabon’s domestic power sector is underdeveloped, although it has vast potential to expand its hydropower. Nonetheless, the country lacks adequate infrastructure to capitalize on its natural resources, as less than 50 percent of the population is connected to the electricity grid. Most installed energy is consumed in urban hubs, while rural electricity access is low. EIA estimates that nearly half of Gabon’s energy consumption is from traditional biomass.

Gabon energy consumption 2010



According to Oil & Gas Journal (OGJ) in 2012, Gabon has 2 billion barrels of proven oil reserves, the fourth-largest in sub-Saharan Africa after Nigeria, Angola, and Sudan. The country’s production of crude oil and lease condensate has decreased by about one-third from its peak of 370,000 bbl/d in 1997 to 246,000 bbl/d in 2010. Most of Gabon’s oil fields are located in the Port-Gentil area and are both onshore and offshore.

Historically, Gabon’s oil production has been concentrated in one large oil field and supported by several smaller fields. As the largest field matured and production declined, a larger field would emerge and replace dwindling production. Dominant fields have included Gamba/Ivinga/Totou (1967-1973), Grondin Mandaros Area (1974-1984), and Rabi (1989-2010). Gabon’s greatest success, the Rabi oil field, significantly boosted the country’s total output in the 1990s and reached 217,000 bbl/d at its peak in 1997. Although Rabi is still one of Gabon’s largest producing fields, it has matured and production has gradually declined to about 23,000 bbl/d in 2010. Since Rabi’s descend, a new large field has not yet emerged, since recent exploration has yielded only modest finds.

Gabon oil other liquids production by field 1965-2010

Sector Organization

In June 2011, the government created a national oil company, the Gabon Oil Company, to increase the government’s involvement in oil production by taking equity stakes in future awards. Gabon did not have a national oil company for over two decades after Société Nationale Petrolière Gabonaise was disbanded in 1987. Traditionally, the oil sector has been regulated by the president’s office and the Ministry of Mines, Energy, and Petroleum. Although ownership of oil and gas resources is vested in the state, foreign companies are allowed to take large equity stakes in exploration and development through production-sharing contracts (PSCs).

The government is currently finalizing new regulatory terms to facilitate new deepwater exploration. The 10th oil license round was scheduled for October 2010, but then cancelled. The round was expected to include 42 deepwater and ultra-deepwater blocks, with a focus on the country’s pre-salt prospects. The government is now engaging in direct negotiations to award the acreage. The government is also expected to strengthen local content requirements by limiting the number of foreign workers in the oil sector to 10 percent and requiring that all executive posts be held by Gabonese. The government agreed to these concessions to mitigate oil worker strikes led by the National Organization of Oil Employees, which temporarily disrupted production in April 2011.

Currently, Gabon’s oil sector is dominated by foreign oil companies. Total is the largest operator in Gabon and has been present for over 80 years. The company’s equity production averaged 71,000 bbl/d in 2009. Shell and its subsidiary Shell Gabon together are the second largest producers followed by Perenco, which produces 65,000 bbl/d from its four offshore fields. The fourth largest, Addax, has interest in five PSCs, covering both offshore and onshore license areas at their five producing fields.

TOP oil producing companies gabon 2011

Exploration and Production

The Gabonese government expects to mitigate the gradual decrease in oil output by encouraging more investment to prolong the life of existing fields. Total is increasing investment to boost production from the offshore Anguille oil field, one of the largest oil producing fields in Gabon. The government has also sought investment from smaller companies willing to develop smaller fields. In the short-term, declines in production from larger fields will continue to be mitigated by smaller fields; nevertheless, in the long-run Gabon’s oil production will depend on the success of new explorations, particularly the prospects of deepwater, pre-salt fields.

Offshore Brazilian pre-salt discoveries have piqued investor interest in Gabon’s pre-salt potential. The country’s pre-salt had been untapped until recently when U.S.-based Harvest Natural Resources struck oil at its Ruche-1 wildcat well in the pre-salt layers offshore Gabon in June 2011. A month following, the company had a second oil discovery at the same well. Brazil’s oil company Petrobras joined pre-salt exploration activities in June 2011, acquiring a 50 percent stake in Ophir Energy’s PSC. Petrobras is expected to apply its extensive experience in Brazil to capture deepwater pre-salt layers in Gabon that have been unexplored. Future discoveries in pre-salt fields could offset the decline from Gabon’s large mature fields.Downstream

Gabon’s downstream sector is very small; the country has one refinery, the Sogara Refinery located at Port-Gentil. After experiencing losses for the past five years, the refinery boosted the production of refined petroleum products by 59 percent in 2010. According to Sogara’s general manager, output increased to more than 18,500 bbl/d from about 11,650 bbl/d in 2009. OGJ estimates that the refinery’s capacity is 24,000 b/cd. Total SA owns about 44 percent of Sogara, the Gabonese government controls about 25 percent, and the remainder is owned by a consortium of companies. Sogara produces petroleum products for export and also supplies the domestic market with kerosene, butane, and gasoil.Exports

About 90 percent of Gabon’s crude oil is exported, since the country’s domestic petroleum consumption is minimal at 18,000 bbl/d in 2010. Crude oil exports consist of Rabi Light and the Mandji blend and have accounted for 80 percent of Gabon’s total exports on average for the last five years. EIA estimates that in 2010, Gabon exported about 225,000 bbl/d of crude oil of which almost half went to the United States. Other top export destinations are the European Union and Malaysia.
Natural Gas

Gabon has 1 trillion cubic feet (Tcf) proven natural gas reserves, according to OGJ. The country’s natural gas resources have not been exploited because Gabon lacks the infrastructure to utilize the natural gas for domestic industry or electricity generation. Nearly all the associated natural gas produced is vented and flared or reinjected. The country produces 73 billion cubic feet (Bcf) of natural gas and only 3 Bcf is consumed by the local market. Power plants in Libreville, Gabon’s capital city, and Port-Gentil, the petroleum hub, consume the most gas in the country.

The latest gas developments in Gabon were initiated by Perenco. In 2005, Perenco agreed to supply gas to various power plants, and since then, the company has installed a network of gas pipelines from the Ganga Field to provide more power to Libreville and Port-Gentil.

Société d'Electricité et d'Eaux du Gabon (SEEG), Gabon’s national utility company, owns and runs Gabon’s electricity sector. The French Company Vivendi currently owns 51 percent of SEEG and is responsible for electricity generation and distribution in Gabon. Conventional thermal power and hydroelectricity account for nearly all of the country’s installed generation capacity. According to EIA estimates in 2009, hydroelectricity net generation is 0.9 Billion kilowatthours (KWH) and thermal electricity net generation is 0.7 Billion KWH.

Total electricity generation  Gabon

Gabon’s urban areas consume a majority of the power generated, while electricity access in rural areas remains low. As of 2009, Gabon’s electrification rate was 36.7 percent and 900,000 people were without electricity, according to the International Energy Agency. Gabon has approximately 6,000 MW of undeveloped hydropower potential, which if exploited, could substantially increase the country’s electrification rate.

Gabon recently launched a plan to develop the electricity sector with the construction of six power plants and 5,000 kilometer transmission lines. The first project anticipated to come online in early 2013 is the 160-MW Poubara hydroelectric dam on the Ogooué River, which is being built by China’s Sinohydro. The hydro plant is expected to supply power to regional manganese mining and for exports to Congo (Brazzaville). Paris-based Bouygues also began construction of a 40-MW hydroelectric dam in northern Gabon in December 2010 and completion is expected in about two years. Gabon recently released plans to build a 180-MW hydroelectric dam in the southern part of the country as well.

Wednesday, February 15, 2012

Shale Gas Development in the United States

What is Shale Gas?

Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.

Does the U.S. Have Abundant Shale Gas Resources?

Of the natural gas consumed in the United States in 2010, almost 90% was produced domestically; thus, the supply of natural gas is not as dependent on foreign producers as is the supply of crude oil, and the delivery system is less subject to interruption. The availability of large quantities of shale gas should enable the United States to consume a predominantly domestic supply of gas for many years and produce more natural gas then it consumes.


The U.S. Energy Information Administration's Annual Energy Outlook 2012(Early Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of technically recoverable natural gas resources as of January 1, 2010. Natural gas from proven and unproven shale resources accounts for 542 Tcf of this resource estimate. Many shale formations, especially the Marcellus, are so large that only small portions of the entire formations have been intensively production-tested. Consequently, the estimate of technically recoverable resources is highly uncertain, and is regularly updated as more information is gained through drilling and production. At the 2010 rate of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to supply over 90 years of use. Although the estimate of the shale gas resource base is lower than in the prior edition of the Outlook, shale gas production estimates increased between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas.
Where is Shale Gas Found?

Shale gas is found in shale "plays," which are shale formations containing significant accumulations of natural gas and which share similar geologic and geographic properties. A decade of production has come from the Barnett Shale play in Texas. Experience and information gained from developing the Barnett Shale have improved the efficiency of shale gas development around the country. Another important play is the Marcellus Shale in the eastern United States. Geophysicists and geologists identify suitable well locations in areas with potential for economical gas production by using both surface and subsurface geology techniques, and seismic techniques to generated maps of the subsurface.

United States Shale Gas Map

Hydraulic fracturing (commonly called "fracking" or "fracing") is a technique in which water, chemicals, and sand are pumped into the well to unlock the hydrocarbons trapped in shale formations by opening cracks (fractures) in the rock and allowing natural gas to flow from the shale into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas producers to extract shale gas economically. Without these techniques, natural gas does not flow to the well rapidly, and commercial quantities cannot be produced from shale.
How is Shale Gas Production Different from Conventional Gas Production?

Conventional gas reservoirs are created when natural gas migrates from an organic-rich source formation into permeable reservoir rock, where it is trapped by an overlying layer of impermeable rock. In contrast, shale gas resources form within the organic-rich shale source rock. The low permeability of the shale greatly inhibits the gas from migrating to more permeable reservoir rocks.

Diagram of a Typical Hydraulic Fracturing Operation

Source: ProPublica,
What Are the Environmental Issues Associated with Shale Gas?

Natural gas is cleaner-burning than coal or oil. The combustion of natural gas emits significantly lower levels of carbon dioxide (CO2) and sulfur dioxide than does the combustion of coal or oil. When used in efficient combined-cycle power plants, natural gas combustion can emit less than half as much CO2 as coal combustion, per unit of electricity output.

However, there are some potential environmental concerns that are also associated with the production of shale gas. The fracturing of wells requires large amounts of water. In some areas of the country, significant use of water for shale gas production may affect the availability of water for other uses, and can affect aquatic habitats.

Second, if mismanaged, hydraulic fracturing fluid — which may contain potentially hazardous chemicals — can be released by spills, leaks, faulty well construction, or other exposure pathways. Any such releases can contaminate surrounding areas.

Third, fracturing also produces large amounts of wastewater, which may contain dissolved chemicals and other contaminants that require treatment before disposal or reuse. Because of the quantities of water used and the complexities inherent in treating some of the wastewater components, treatment and disposal is an important and challenging issue.

Finally, according to the United States Geological Survey, hydraulic fracturing "causes small earthquakes, but they are almost always too small to be a safety concern. In addition to natural gas, fracking fluids and formation waters are returned to the surface. These wastewaters are frequently disposed of by injection into deep wells. The injection of wastewater into the subsurface can cause earthquakes that are large enough to be felt and may cause damage."

Tuesday, February 14, 2012

Uzbekistan Energy Report

Uzbekistan has a highly energy-intensive economy as much of the infrastructure is inefficient and needs upgrading. Uzbekistan holds sizeable hydrocarbon reserves, mostly natural gas, yet faces a myriad of challenges in bringing those reserves to world markets. Uzbekistan is geographically far from end-use markets and is landlocked on all sides. The country lacks sufficient pipelines to export more hydrocarbons and suffers from an inefficient and older energy infrastructure. Uzbekistan’s tight regulatory environment on investment inflows has significantly slowed the necessary foreign technical and financial assistance to develop reserves and upgrade the country’s infrastructure systems. Also, other hydrocarbon-rich Eurasian states with more favorable investment climates and greater access to markets pose competition for Uzbekistan. The country has taken steps to monetize its gas reserves in recent years through forging partnerships with Russian and Asian firms for oil and gas production.

Consumption of total primary energy for Uzbekistan reached 2.353 quadrillion Btu in 2008, approximately 80 percent of which came from natural gas, while petroleum products made up 0.302 quadrillion Btu or 13 percent of the market share. The remaining fuel sources are small quantities of hydropower and coal used for electricity generation and industry. Natural gas, the key fuel source for the country, accounts for 70 percent of the electric generation and 90 percent of heat production in 2008. The government policy intends to increase the share of coal-fired power over the next two decades.

Uzbekistan map


The Oil and Gas Journal (OGJ) estimates that Uzbekistan had 594 million barrels of proven oil reserves in 2012, 171 discovered oil and natural gas fields, 51 of which produce oil and 17 of which produce gas condensates. Uzbekistan’s petroleum production consists of roughly 60 percent high-sulfur crude and 40 percent condensates from natural gas fields. Existing oil and gas fields are depleting faster than new discoveries are coming online, spurring the need for further investment.

The majority of the known oil reserves in Uzbekistan are in the Bukhara-Khiva region in the southeast of the country, and most fields are small apart from the sizeable Kokdumalak field. Other oil- and gas-rich areas are the Ustyurt Plateau/Aral Sea region, Southwest Gissar, Surkhan-Darya, and the Ferghana Valley. The Ferghana Basin, bridging Uzbekistan, Kyrgyzstan, and Tajikistan, reportedly contains and total recoverable oil of 4 billion barrels including 3 billion barrels of undiscovered reserves according to the U.S. Geological Survey (USGS).

Oil map Uzbekistan

Source: IEA

Exploration and Production

Because of ageing infrastructure and a dearth of foreign investment and capital, production rapidly declined after 2003. During 2010, Uzbekistan produced 59,000 barrels of oil per day (bbl/d), a 60-percent decline from 2000 levels.

Despite having reserve levels similar to those of its neighbor Turkmenistan, Uzbekistan produces significantly less oil due to a historical lack of investment and limited export options. EIA projects that oil production continues falling through 2013.

The Bukhara-Khiva region in the southwest region of the country accounts for about 70 percent of Uzbekistan’s oil production. Uzbekistan signed several production sharing agreements (PSAs) with foreign oil companies to refurbish existing fields and develop new basins in this region along the border with Turkmenistan. Many of these fields hold both oil and gas condensates. Lukoil and CNPC hold stakes in the Southwest Gissar and Bukhara-Kiva oil basins, respectively, through agreements with Uzbekneftegaz, Uzbekistan’s state oil company. Lukoil produced 1,000 bbl/d in 2009 in its Southwest Gissar basin which holds an estimated 44 million barrels, and expects to raise the level to 6,000 bbl/d by 2012. CNPC and Uzbekneftegaz are developing over 20 fields including the Umid field, containing 18 million barrels, in Bukhara-Kiva.

CNPC is exploring the Mingbulak field that is part of the Ferghana basin in eastern Uzbekistan as part of an energy cooperation agreement between Uzbekistan and China. Proven reserves are still unknown because some of the oil is located in sub-salt portions of the basin, proving challenging for exploration.

Another potential source of oil supply is from oil shale reserves in the Sangruntau deposit in Uzbekistan’s northern Navoi region. Uzbekistan plans to attract $850 million in domestic and foreign investment by 2015 to explore and develop oil shale projects. In a joint venture (JV) with Japan Oil, Gas & Metals National Corporation (JOGMEC), Uzbekistan intends to process the oil shale at a new facility by 2013.

Uzbekistan Oil Projects and Investments

Oil and Gas Sector Organization

Uzbekistan attracts less foreign direct investment (FDI) than other Caspian nations, and investment in the hydrocarbon industry is currently insufficient to raise oil and condensate production. However, Uzbekistan recently began easing legislation to attract foreign capital. According to the World Bank, total net inflow of FDI to Uzbekistan in 2009 was $750 million, over 4 times the amount invested in 2006.

Uzbekneftegaz, the state oil and gas holding company, is responsible for all exploration, production, and downstream operations within Uzbekistan. This national oil company was restructured in 2004 to include four subsidiaries covering various upstream and downstream operations. The government made several unsuccessful attempts to privatize 49 percent of Uzbekneftegaz.

In 2004, Uzbekistan passed PSA legislation to attract more foreign investment. Also, in 2007, the country lowered taxes on subsoil hydrocarbon extraction to give producers more incentives to reverse oil production declines.

Uzbekistan attracts most energy sector foreign investment through PSAs or JVs primarily with Russian or Asian energy companies: primarily, Gazprom, Lukoil, CNPC, Petronas, and KNOC of Korea. Lukoil, one of the largest foreign investors in Uzbekistan, announced plans quadruple its total cumulative investment in Uzbekistan to $5 billion by 2017 from the total of $1.5 billion in 2010.

Uzbekistan also signed several energy cooperation agreements with other companies such as India’s GAIL and ONGC, PetroVietnam, and ExxonMobil to attract their technical expertise and support in the country’s hydrocarbon production. Despite gradual steps to improve its foreign investment climate, Uzbekistan still faces serious hurdles to develop its hydrocarbon sector.

Refining and Gas-to-Liquids

Uzbekistan has three refineries at Ferghana, Alty-Arik, and Bukhara, with a total refining capacity of 222,300 bbl/d. Because of the country's decline in oil production in recent years, Uzbek refineries are operating at only 60 percent of design capacity. The country announced plans in January 2011 to spend $200 million modernizing both refineries to increase the ratio of light products to 95 percent. Uzbekistan's limited refined product exports move by rail and road to neighboring countries and ports on the Black Sea.

Uzbekistan plans to reduce its oil product imports by converting some of its abundant natural gas reserves to oil products using gas-to-liquids (GTL). The Shurtan GTL plant, located in the Kashkadarya region, is slated to convert 120 Bcf/y of natural gas and gas condensates to about 35,000 bbl/d of oil products. The project’s current equity partners, Uzbekneftegaz (44.5 percent), Sasol of South Africa (44.5 percent), and Petronas (11 percent), completed the feasibility study at the end of 2011 and plan to bring the plant online by 2017.

Oil Exports and Imports

Uzbekistan will remain a net oil importer as long as production declines. Oil demand exceeds supply by nearly two-fold. Domestic oil consumption reached an estimated 139,000 bbl/d in 2010 and has remained relatively constant since the mid-1990s, averaging 150,000 bbl/d. However, the country’s goal is to lower oil import dependence and increase exports.

Uzbekistan imports small amounts of crude oil mainly from Kazakhstan and exports refined products. Refined products are transported by rail or vehicles to surrounding countries.

Uzbekistan has virtually no international oil pipeline infrastructure except a pipeline linking the Kazakh Shymkent refinery to the Chardzhou refinery in northeastern Turkmenistan. A smaller petroleum products pipeline linking Shymkent, Kazakhstan to Tashkent, the Uzbek capital, resumed imports in 2003 after Uzbekistan allowed oil imports to re-enter the country. Uzbekistan's only current option to export crude oil is to reverse an existing pipeline that brings oil from Omsk, Russia, to Uzbek refineries.

Natural Gas

According to OGJ, Uzbekistan holds an estimated 65 Tcf (Trillion cubic feet) of proven natural gas reserves as of 2012, ranking it the fourth highest in the Eurasia region and nineteenth in the world. Uzbekistan produces natural gas from 52 fields with 12 major deposits, accounting for over 95 percent of the country’s gas production. These deposits are concentrated on the Uzbek side of the Amu Darya Basin in the southeastern region and in the Central Ustyurt plateau near the Aral Sea in the western region of the country.

Top Eurasia Region Gas Reserves by Country

Exploration and Production

Since independence in 1992, Uzbekistan increased its natural gas production by 44 percent, from 1.5 Tcf/y to over 2.1 Tcf/y in 2010. Production peaked at 2.4 Tcf/y in 2008. Uzbekistan is currently the second largest gas producer in the Eurasia region (after Russia and passing Turkmenistan in 2009) and ranks in the top thirteen natural gas-producing countries in the world.

Uzbekistan's natural gas fields, concentrated in the southwest region, were heavily exploited in the 1960's and 1970's. Production from existing fields, such as Kokdumalak and Shurtan, has reached a plateau. In order to offset declines from mature fields and boost overall production, Uzbekistan announced plans to spend at least $1 billion (two-thirds funded by Uzbekneftegas and one-third by domestic and international banks) by 2020 on increasing gas reserves and infrastructure for fields in the southwestern Gazli region. The national company also reported in 2011 that it will invest $800 million in the next four years to augment gas reserves and exports from four older fields in the southern Kashkadarya region, which produce 1.7 Tcf/y, over three-quarters of Uzbekistan’s total production.

Uzbekistan Natural Gas Production and Consumption
Uzbekistan signed several accords and PSAs in the last four years with Russian and Asian companies to develop new gas projects and revamp depleting fields. Lukoil holds two agreements with Uzbekneftegaz for production at the Kandym-Khauzak project and the Southwest Gissar project as detailed in the following table. Lukoil’s goal is to increase its total gas production in Uzbekistan to over 600 Billion cubic feet (Bcf) by 2017 and export some of the gas to China when transportation capacity on the Central Asia-China Pipeline expands.

Gazprom and Uzbekneftegaz signed an agreement on strategic cooperation in 2002 so that the Russian company can purchase long-term Uzbek gas exports and participate in more exploration and production supply ventures. The Russian company currently has two production sharing agreements in northwestern Uzbekistan.

The North and West Ustyurt plateau near the Aral Sea garnered attention from several investors, and currently there are four PSAs to explore and produce gas in this area. The Aral Sea exploration block is a PSA consisting of the following stakeholders: CNPC, Lukoil, KNOC, and Uzbekneftegaz. Uzbekneftegaz plans to transport gas from the Aral Sea using the Bhukara-Urals pipeline or the Central Asia Center pipeline system.

Uzbekistan Natural Gas Projects and Investments

Gas Flaring and Transportation

Gas from fields associated with oil production is sometimes flared, and there are losses on the system due to pressure declines. Uzbekneftegaz estimates that associated gas utilization is currently 40 percent. According to estimates from a World Bank commissioned study conducted by the National Oceanic and Atmospheric Administration’s (NOAA), Uzbekistan flared an estimated 67 Bcf/y in 2010 and ranks as one of the top 20 gas flaring countries; however flaring has declined overall since 2006. Uzbekneftegaz reports it will invest $123 million to increase gas utilization and monetize supply that is currently flared or shut in at associated fields.

Natural Gas Exports

Uzbekistan consumes nearly 80 percent of its gas production, or about 1,600 Bcf/y in 2010, for domestic use in the electric and heating sectors. Uzbekistan's lack of sufficient gas export pipeline options and heavily regulated and subsidized prices limit the country's gas exports. With one of the highest populations in the region – 27.8 million in 2009, export capabilities compete with domestic demand for supply. However, Uzbekistan plans to triple its gas exports by 2020 and diversify gas markets.

Uzbekistan exported approximately 24 percent of its gas production in 2010, and exports have generally increased since 2002. Uzbekistan sends over half of its natural gas exports to Russia and the remainder to neighboring states such as Kazakhstan, Kyrgyzstan, and Tajikistan. Uzbekistan is also a transit country for Turkmenistan's gas exports to Russia and China.

Uzbekneftegaz signed new agreements with Gazprom and CNPC in 2010. The agreement with Gazprom covers a 2-year extension of the current agreement in which Russia contracted to import over 350 Bcf/y through 2012. In 2010, Uzbekistan signed a supply agreement with CNPC for China to take 350 Bcf/y once the capacity on the Central Asia-China Pipeline expands in 2014. Furthermore, China's Eximbank agreed to provide $74 million in order to modernize Uzbekistan's gas distribution network to facilitate the flows to China.

Uzbekistan natural gas pipelines

Natural Gas Pipeline Routes

Uzbekistan is landlocked on both sides and mainly serves as a transit country for Turkmen gas flowing to Russia and China. The country's distribution system and gas processing capabilities are sufficient to meet its domestic gas transmission requirements, and the key pipeline connecting the Ustyurt and Bukhara-Kiva gas regions with the export pipelines is the Gazli-Kagan pipeline. Uzbekistan is in the process of increasing its gas exports to new markets such as China and to existing markets through these pipelines

Central Asia Center Pipeline (CAC)

The Central Asia-Center pipeline is the key route through which Uzbekistan exports its gas to Russia and Gazprom's natural gas system. The western branch delivers Turkmen natural gas from near the Caspian Sea region to the north, while the eastern branch pipes natural gas from eastern Turkmenistan and southern Uzbekistan to western Kazakhstan. Turkmenistan has been the chief exporter of natural gas via the Central Asia-Center pipeline. Both branches have a combined design capacity of 3,530 Bcf/y; however because of the poor technical conditions, actual capacity is about half of this amount.

Uzbekistan signed a deal with Gazprom in late 2008 that would involve renovation of the CAC's eastern section and construction of a new parallel pipeline, adding up to 1,060 Bcf/y of capacity.

Central Asia-China Pipeline (Turkmenistan to China via Uzbekistan)

CNPC established the Sino-Turkmenistan Gas Pipe Corporation to construct a 1,140-mile (1,833-kilometer) gas export pipeline from Turkmenistan's eastern fields through Uzbekistan to western China and the interconnection with China's West-East pipeline. CNPC originally anticipated transporting up to 1,060 Bcf/y of gas on the Central Asia-China Pipeline which began operations in December 2009. However, in mid-2011, CNPC announced the pipeline's capacity could rise to over 2,100 Bcf/y by 2015.

Although Turkmenistan is designed to be the key contributor of gas to China on this pipeline, Uzbekistan is also slated to transport up to 350 Bcf/y of its own gas to China through the system as well. Currently, Uzbekistan transits only Turkmen gas to China through the pipeline, but the country finalized a gas supply deal with China at the end of 2011. China agreed to build the pipeline's third strand with a capacity of 890 Bcf/y, allowing Uzbekistan to begin exporting its gas to China by 2014.

Bukhara-Urals Pipeline

Lack of maintenance on the CAC caused Uzbekistan to re-open the moth-balled Bukhara-Urals Pipeline in 2001 to transit increasing volumes of Turkmen gas. This pipeline runs from the Dauletabad field in southeastern Turkmenistan through the Bhukara gas region in Uzbekistan, to Kazakhstan, and feeds into the pipeline system in Russia. The pipeline capacity is currently 706 Bcf/y; however, it operates at only a quarter of its capacity, at around 177 Bcf/y and needs refurbishing.

Tashkent- Bishkek-Almaty Pipeline

Uzbekistan's main natural gas export pipeline is the Tashkent-Bishkek-Almaty pipeline which runs from eastern Uzbekistan through northern Kyrgyzstan to southern Kazakhstan and has a capacity of 113 Bcf/y. The pipeline is the main source of natural gas for Kyrgyzstan and southern Kazakhstan. Various issues regarding irregular supplies by Uzbekistan and mounting debts by both Kazakhstan and Kyrgyzstan for supplies already received have led to increased tension among the three neighbors in the past.

Monday, February 13, 2012

Turkmenistan Energy Report

Turkmenistan has some of the largest natural gas reserves in the world, yet the country faces a myriad of challenges in bringing those reserves to world markets. It is geographically far from end-use markets and lacks sufficient pipeline infrastructure to export more hydrocarbons. Also, other hydrocarbon-rich Central Asian and Caspian states with more favorable investment climates and greater access to markets pose competition for Turkmenistan. The country is eager to diversify export routes for its oil and gas resources outside of the pipelines going to Russia, but must obtain capital, technical assistance, and political support for alternative pipelines.

After about 15 years of isolation and a political regime change, Turkmenistan began the process of renewing diplomatic relations with several countries including Russia, China, Europe, the US, and other Central Asian neighbors in 2007. Foreign energy firms experienced extreme political challenges and investment impasses prior to 2007, and several exited the country leaving a dearth of investment. Since then, Turkmenistan created a more business-friendly environment, attempting to attract foreign investment to increase both oil and gas production and expand its export portfolio.

Turkmenistan map


Turkmenistan had proven oil reserves of roughly 600 million barrels in January 2012 based on estimates by Oil and Gas Journal (OGJ). Most of the country's oilfields are situated in the South Caspian Basin and the Garashyzlyk onshore area in the west of the country. In addition, Turkmenistan claims its section of the Caspian Sea contains 80.6 billion barrels of oil, though much is unexplored.

Oil map Turkmenistan

Source: IEA

Oil and Gas Sector Organization

In 1998, Turkmenistan restructured the Oil and Gas Ministry to include five state-run companies, which control the country's hydrocarbon activities. These companies include the following: Turkmenneftegaz (controls purchases, distribution, and exports of both fuels and oil refining); Turkmenneft (produces oil in the western region of the country); Turkmengaz (produces gas); Turkmenneftegazstroi (construction company for hydrocarbon industry); and Turkmengeologia (conducts hydrocarbon exploration).

Seeking to attract more foreign investment and diversify export routes, the Turkmen government began reforming the country's energy sector and regulatory environment. In March 2007, the government established a hydrocarbon regulatory authority, State Agency on Management and Use of Hydrocarbon Resources, to issue licenses and contracts for oil and gas field development and provide greater revenue transparency. In 2008, Turkmenistan also passed a Hydrocarbon Law to provide greater legal transparency in ownership of oil and gas projects. According to the World Bank, foreign direct investment in Turkmenistan was $1.4 billion in 2009, up 65 percent from 2008, and country officials anticipate higher investment in the future.

International companies can participate in joint ventures (JVs) or production sharing agreements (PSAs) with Turkmenneft for offshore oil and gas blocks in the Caspian Sea. Turkmenistan currently limits investment opportunities for international companies to offshore oil and gas developments, with exception for the PSA with China vis-à-vis the Bagtyiarlyk onshore natural gas project in the country's southeastern region. In 2009, the Turkmen government signed several PSAs with foreign companies, including Russia's Itera and Germany's RWE, for offshore field development in the Caspian Sea.

Exploration and Production

Turkmenistan's oil production has increased from 110,000 bbl/d in 1992 to approximately 202,000 barrels per day (bbl/d) in 2010. Production peaked at 213,000 bbl/d in 2004 before declining slightly. Short-term forecasts keep production relatively flat through 2013. About half of production is slated for the domestic market that consumed slightly more than 100,000 bbl/d.

Turkmenistan Oil production and Consumption 

Oil deposits are located in disputed areas of the Caspian Sea, and without an agreement between Iran, Azerbaijan, and Turkmenistan on maritime boundaries, these fields likely will remain undeveloped. The disputed Kyapaz-Serdar oil and gas field linking the Turkmen and Azeri maritime border in the Caspian Sea holds between 367 and 700 million barrels of recoverable reserves, according to various sources. Turkmenistan sought international arbitration to settle the boundary dispute with Azerbaijan in 2009, though this issue alongside Turkmenistan's claims to portions of the Azeri and Chirag fields being developed by Azerbaijan, are still unresolved.

Since 2007, the Turkmen government began engaging with several foreign oil companies to develop Turkmenistan's part of the Caspian shelf. The table below is a snapshot of current oil agreements signed with foreign investors.

Turkmenistan Oil Projects and Investments

The government is working towards increasing oil production, but the sector struggles to meet its growth goals due to a shifting interest to natural gas production, lagging foreign investment, and heavy competition for investment within the Caspian region. According to Turkmen officials, the country aims to produce over 1.3 million bbl/d in offshore and onshore oil by 2030; however other industry sources forecast that production will be less than 300,000 bbl/d in this period. Most of the production growth in recent years is from Dragon Oil's offshore block (from United Arab Emirates), offshore Cheleken block and Eni's Nebit Dag field in the onshore western area. Dragon Oil realized a production increase of 25 percent in the Cheleken block in the first half of 2011 and anticipates doubling its oil production in Turkmenistan to 100,000 bbl/d by 2015.


Turkmenistan has two major refineries, the Seidi (Chardhzou) and Turkmenbashi, with a combined total capacity of 237,000 bbl/d. According to IHS Global Insight, Turkmenistan's refinery system has a low utilization rate of about 50 percent of capacity. Foreign oil companies generally export their share as crude oil while Turkmen companies usually refines its crude oil production for domestic use or for petroleum product exports. The government announced plans to construct three more refineries, expand capacity at the current refineries, and raise the total capacity to 600,000 bbl/d by 2030 based on the country's goal of increasing production during this timeframe.

Oil Exports

Turkmenistan is a small net exporter of crude and refined oil. Oil export options for Turkmenistan are limited. Turkmenistan has almost no international oil pipelines apart from a cross-border pipeline in the east running from Kazakhstan and Uzbekistan where Turkmenistan can import Uzbek crude oil to feed the Chardhzou refinery. A small amount of crude oil is exported from Turkmenistan across the Caspian Sea to Azerbaijan and the Russian port of Makhachkala. Securing pipeline access in Russia has been a problem due to the poor quality of some Turkmen crude.

A portion of Turkmenistan's total petroleum exports is in the form of refined products. EIA reports exports of crude and total refined products were 48 bbl/d and 74 bbl/d, respectively, in 2008.

Dragon Oil held an oil swap deal with Iran from 1998 until 2010. Under this agreement, Dragon Oil transferred over half of its crude oil production in Turkmenistan to northern Iranian refineries in exchange for equal volumes exported from the Persian Gulf. In 2010, Dragon Oil stopped sending oil to Iran due to tighter international sanctions on Iran and diverted the volumes to Azerbaijan and the Baku-Tbilisi-Ceyhan pipeline.

Natural Gas
Natural gas reserves by country 2012

Natural gas plays a significant role in Turkmenistan's overall energy consumption. The country's consumption of total primary energy for Turkmenistan reached 1 quadrillion Btu in 2008. Of this amount, approximately 78 percent (0.78 quadrillion Btu) was from natural gas, while 22 percent of the market share (0.22 quadrillion Btu) was from petroleum products. According to the International Energy Agency, roughly one-third of the country's gas fuels power generation while another third helps to operate the gas industry's upstream and processing sector. All of Turkmenistan's power generation facilities are gas-fired.

Exploration and Production

Despite vast gas reserves, limited export and investment options pose challenges to monetizing and producing gas resources. A majority of Turkmen gas travels to Russia where it is consumed or transits through Russia to end markets in Europe. Since 1992, Russia, the key export market for Turkmenistan, has exerted significant influence over export prices of gas resources charged by the Central Asian state. As a result of a pipeline explosion on the Central Asian Center export pipeline to Russia in April 2009, Turkmen gas production was shut in and suffered serious declines. Gas production fell almost 50 percent from a high of 2.5 Tcf/y in 2008 to 1.3 Tcf/y in 2009. Following the pipeline repair and a new pricing agreement signed with Russia in January 2010, Turkmenistan raised production to 1.6 Tcf/y in 2010 from 1.3 Tcf/y in 2009. However, Russia agreed to accept about 400 Bcf/y or only one-third of the volumes it imported prior to the explosion and at a lower import price, resulting from its declining exports to Europe.

Turkmenistan is seeking ways to boost gas production as well as release the current shut-in gas volume by diversifying its portfolio of export markets. The country anticipates increasing production as exports via new pipelines to China and Iran ramp up.

In November 2010, Turkmenistan's Ministry of Oil, Gas, and Mineral Resources said the country's energy strategy is to more than triple gas production to over 8.1 Tcf/y by 2030. Most of the gas available for future development is high in hydrogen sulfide and carbon dioxide and has a greater pressure and temperature, and these factors pose technical challenges, requiring greater capital costs for exploration and development.

Turkmenistan Natural gas production and consumption

The Dauletabad field, located in the Amu Darya basin in the southeast, is one of Turkmenistan's largest and oldest gas-producing fields with estimated reserves of 60 Tcf. The field produced approximately 1.2 Tcf/y in 2010 or most of Turkmenistan's gas supply, however, production is declining.

CNPC is the only foreign company with direct access to an onshore development, the Bagtyiarlyk project near the Amu Darya River, through a 35-year production sharing agreement. The project came online at the end of 2009 with a capacity of 182 Billion cubic feet (Bcf) per year and began feeding gas to the Central Asia China pipeline. By 2012, the field is expected to ramp up production capacity to 460 Bcf/y to supply gas to China.

In 2006, Turkmenistan announced the discovery of the South Yolotan deposit, located in the southeastern Murgab Basin north of the Dauletabad field. An independent audit estimated in October 2011 that the field's potential reserves are at least 460 Tcf and possibly as high as 740 Tcf, which would make South Yolotan the second largest field in the world. In order to aid in financing the field development, the China Development Bank provided a $4 billion loan in 2009 for the project's first phase of development, and, in 2011, pledged another $4.1 billion for the second phase. Industry analysts expect the field to be online by 2013 and to export gas via the Central Asia-China Pipeline.

The Turkmen government is open to foreign investment and ownership in oil and gas fields in the country's offshore section of the Caspian Sea. Most gas from the Caspian Sea is associated with oil production and is currently flared until companies can monetize the supply. Petronas and Dragon Oil produce gas through their respective PSAs in the Diyarbekir (Block 1) and Cheleken fields. Petronas currently flares gas from Block 1 while the company seeks ways to commercialize production. Turkmengaz signed a gas purchase agreement in July 2011 with Petronas, and Malaysia and Turkmenistan signed a cooperation agreement enabling Petronas to build a 360 Bcf/y-capacity gas processing plant on the Caspian coast to receive the gas from Block 1.


Turkmenistan has become a leading gas exporter in the Caspian and Central Asian region. The country exports a majority of its gas because production rates are more than double domestic demand estimated at 720 Bcf/y in 2010. The International Energy Agency forecasts exports will rebound and rise to about 3,180 Bcf/y by 2035.

Turkmenistan signed several agreements between 2007 and 2009 with international parties interested in tapping its gas reserves and developing pipeline infrastructure. Turkmenistan has historically relied on Russia as the primary export market and transit country for its gas, though recently constructed pipeline routes to China and Iran have opened new opportunities. In 2009, Turkmenistan exported 636 Bcf/y, dropping from over 1,700 Bcf/y in 2007 and 2008, as a result of the supply disruption to Russia discussed in the Exploration and Production section.

At the beginning of 2008, Turkmenistan ceased sending supplies to Iran due to a gas dispute; however, the countries signed a new agreement in February 2009. Iran agreed to import 350 Bcf/y, though imported only 177 Bcf/y that year. This amount is expected to increase as Turkmenistan tries to offset the fall in exports to Russia and fill capacity on a second pipeline to Iran commissioned in 2010. Total capacity for both pipelines is 700 Bcf/y.

China began importing Turkmen gas at the end of 2009 and expects to increase supplies as the pipeline capacity and production levels increase. In July 2007, China signed a 30-year gas purchase agreement with Turkmenistan to take 1,100 Bcf/y. CNPC's fields in the Amu Darya/Bagtyiarlyk contract area should supply about 460 Bcf/y of the gas with the remaining 600 Bcf/y of contract exports to come from existing fields and the South Yolotan. China and Turkmenistan signed another agreement in late 2011 that could add another 1,200 Bcf/y, bringing the total potential volume of gas exports to China to nearly 2,300 Bcf/y.

Asia Natural Gas Map

Source: IEA


In an effort to open up more export routes in addition to the main pipeline to Russia, Turkmenistan has partnered with other countries to build gas infrastructure and pipelines. Two pipelines to Iran and China began operations recently, and other routes are under consideration. Maximum existing gas export capacity from Turkmenistan is now close to 3,500 Bcf/y.

Central Asia Center Pipeline (CAC)

The Central Asia-Center pipeline is the key route through which Turkmenistan exports its gas to Russia and Gazprom's natural gas system. The western branch delivers Turkmen natural gas from near the Caspian Sea region to the north, while the eastern branch pipes natural gas from eastern Turkmenistan and southern Uzbekistan to western Kazakhstan. Both branches have a combined design capacity of 3,530 Bcf/y; however, because of the poor technical conditions, actual capacity is about half of this amount.

Korpezhe-Kurt Kui Pipeline (Turkmenistan to Iran)

This 120-mile (200-kilometer) pipeline was built in 1997 and was the first Central Asian natural gas pipeline to bypass Russia. With a capacity of almost 477 Bcf/y, Turkmenistan has been able to supply Iran with roughly 212 Bcf of natural gas per year. The terms of the 25-year contract between the two countries stipulates that 35 percent of Turkmen supplies are allocated as payment for Iran's contribution to building the pipeline.

Dauletabad-Khangiran Pipeline (Turkmenistan to Iran)

A second pipeline with a capacity of 212 Bcf/y to Iran was initiated in January 2010, enabling Turkmenistan to expand its export options. The second phase of the $550 million pipeline project was inaugurated in November 2010, which should raise capacity to 424 Bcf/y.

Central Asia-China Pipeline (Turkmenistan to China)

CNPC established the Sino-Turkmenistan Gas Pipe Corporation to construct a 1,140-mile (1,833-kilometer) gas export pipeline from Turkmenistan's eastern fields through Uzbekistan to western China and the interconnection with China's West-East pipeline. CNPC originally anticipated transporting up to 1,060 Bcf/y of gas on the Central Asia-China Pipeline which began operations in December 2009. However, in mid-2011, CNPC announced the pipeline's capacity could rise to over 2,100 Bcf/y by 2015. The inter-governmental gas supply deal between China and Turkmenistan includes the 35-year Bagtyyarlyk PSA, providing 460 Bcf/y from the Chinese production share and 600 Bcf/y from Turkmenistan's other southeastern gas fields such as South Yolotan.

Bukhara-Urals Pipeline

Lack of maintenance on the CAC caused Uzbekistan to re-open the moth-balled Bukhara-Urals Pipeline in 2001 to transit increasing volumes of Turkmen gas. This pipeline runs from the Dauletabad field in Turkmenistan through Uzbekistan and Kazakhstan to Orsk, Russia. The pipeline capacity is currently 706 Bcf/y; however, it operates at only a quarter of the capacity at around 177 Bcf/y, and is in need of modernization.

East-West Pipeline

Turkmenistan initiated the construction of the East-West Pipeline in May 2010 to connect Turkmenistan's southeastern gas fields to the Caspian Sea and serve as a potential transit link to Europe via routes along the Caspian. The pipeline capacity is expected to be 1,060 Bcf/y, coming on stream in mid-2015.

Turkmenistan-Afghanistan-Pakistan-India Pipeline (TAPI)

An additional way for Caspian region exporters to supply Asian demand would be to pipe oil and natural gas through Iran to the Persian Gulf, or southwest to Afghanistan. The Afghanistan option, which Turkmenistan has been promoting, would entail building pipelines across Afghan territory to reach markets in Pakistan and possibly India. The Trans-Afghan pipeline, also called the Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline, would span over 1,000 miles from a point in Turkmenistan to Fazilka (India) on the Pakistan-India border and have a proposed capacity of over 1,200 Bcf/y. Majors issues holding up construction are supply security concerns, uncertainty of pricing and fees, and lack of financial commitments. India and Pakistan suggested paying below market prices, and finalization of the sales and purchase agreements presents a challenge to the negotiations.

The four countries involved signed a Gas Pipeline Framework Agreement and Inter-Governmental Agreement in December 2010, and Turkmenistan and Pakistan signed a Heads of Agreement in November 2011 regarding import prices. However, the likelihood of such a pipeline coming online in the next few years is very slim due to the logistical and security challenges.

Trans-Caspian Pipeline (TCGP)

A proposal to build the Trans-Caspian Pipeline would bypass both Russia and Iran to carry Turkmen gas across the Caspian Sea to Azerbaijan and connect with pipelines en route to Europe. This proposed 1,060-Bcf pipeline could connect to the South Caucasus pipeline flowing gas to Turkey and then to the planned Nabucco pipeline to southeastern Europe. Disputes over Caspian seabed jurisdiction between Turkmenistan and Azerbaijan could complicate the project's viability.