India Energy Profile – Growing Consumer Of Oil And Gas

With high economic growth rates and over 15 percent of the world’s population, India is a significant consumer of energy resources. In 2009, India was the fourth largest oil consumer in the world, after the United States, China, and Japan. Despite the global financial crisis, India’s energy demand continues to rise. In terms of end-use, energy demand in the transport sector is expected to be particularly high, as vehicle ownership, particularly of four-wheel vehicles, is forecast to increase rapidly in the years ahead.

India lacks sufficient domestic energy resources and imports much of its growing energy requirements. In addition to pursuing domestic oil and gas exploration and production projects, India is also stepping up its natural gas imports, particularly through imports of liquefied natural gas.

According to the International Energy Agency (IEA), coal/peat account for nearly 40 percent of India’s total energy consumption, followed by nearly 27 percent for combustible renewables and waste. Oil accounts for nearly 24 percent of total energy consumption, natural gas six percent, hydroelectric power almost 2 percent, nuclear nearly 1 percent, and other renewables less than 0.5 percent. Although nuclear power comprises a very small percentage of total energy consumption at this time, it is expected to increase in light of international civil nuclear energy cooperation deals. According to the Indian government, nearly 30 percent of India’s total energy needs are met through imports.

IEA data for 2008 indicate that electrification rates for India were nearly 65 percent for the country as a whole. In urban areas, 93 percent had access to electricity compared to rural areas where electrification rates were approximately 50 percent. Roughly 400 million people do not have access to electricity in India.

Oil

According to Oil & Gas Journal (OGJ), India  had approximately 5.6 billion barrels of proven oil reserves as of January 2010, the second-largest amount in the Asia-Pacific region after China. India’s crude oil reserves tend to be light and sweet, with specific gravity varying from 38° API in the offshore Mumbai High field to 32° API at other onshore basins.

India produced roughly 880 thousand barrels per day (bbl/d) of total oil in 2009 from over 3,600 operating oil wells. Approximately 680 thousand bbl/d was crude oil, the remainder was other liquids and refinery gain. In 2009, India consumed nearly 3 million bbl/d, making it the fourth largest consumer of oil in the world. EIA expects approximately 100 thousand bbl/d annual consumption growth through 2011.

The combination of rising oil consumption and relatively flat production has left India increasingly dependent on imports to meet its petroleum demand. In 2009, India was the sixth largest net importer of oil in the world, importing nearly 2.1 million bbl/d, or about 70 percent, of its oil needs. The EIA expects India to become the fourth largest net importer of oil in the world by 2025, behind the United States, China, and Japan.

Nearly 70 percent of India’s crude oil imports come from the Middle East, primarily from Saudi Arabia, followed by Iran. The Indian government expects this geographical dependence to rise in light of limited prospects for domestic production.

Sector Organization

Though the government has taken steps in recent years to deregulate the hydrocarbons industry and encourage greater foreign involvement, India’s oil sector is dominated by state-owned enterprises. India’s state-owned Oil and Natural Gas Corporation (ONGC) is the largest oil company and dominates India’s upstream sector. State-owned Oil India Limited (OIL) is the next largest oil producer. Other major state-run players include the Indian Oil Corporation (IOC) and the Gas Authority of Indian Limited (GAIL). In addition, the private Indian firm, Reliance Industries Limited, is becoming a significant operator in the oil sector and is the largest private oil and gas company in the country. Cairn India, a branch of UK-based Cairn Energy, and BG Exploration are also important private sector operators in the industry.

As a net importer of oil, the Indian government has policies aimed at increasing domestic exploration and production (E&P) activities. As part of an effort to attract oil majors with deepwater drilling experience and other technical expertise, the Ministry of Petroleum and Natural Gas created the New Exploration License Policy (NELP) in 2000, which for the first time permits foreign companies to hold 100 percent equity ownership in oil and natural gas projects. Despite this, international oil and gas companies currently operate a small number of fields.

India’s downstream sector is also dominated by state-owned entities. The Indian Oil Corporation (IOC) is the largest state-owned company in the downstream sector, operating 10 of India’s 18 refineries and controlling about three-quarters of the domestic oil pipeline transportation network. Reliance Industries opened India’s first privately-owned refinery in 1999, and has gained a considerable market share in India’s oil sector.

Exploration and Production

Most of India’s crude oil reserves are located offshore, in the west of the country, and onshore in the northeast. Substantial reserves, however, are located offshore in the Bay of Bengal and in Rajasthan state. India’s largest oil field is the offshore Mumbai High field, located north-west of Mumbai and operated by ONGC. Another of India’s large oil fields is the Krishna-Godavari basin, located in the Bay of Bengal. Block D6 in the Krishna-Godavari basin, operated by Reliance Industries, began oil production in September 2008.

The primary mechanism through which the Indian government has promoted new E&P projects has been the NELP framework. The latest round of auctions, NELP VIII, was launched in April 2009 and attracted nearly $1.1 billion in investment. India currently plans to launch the NELP IX bidding round in the third quarter of 2010.

Overseas E&P

In recent years, Indian national oil companies have increasingly looked to acquire equity stakes in E&P projects overseas. The most active company abroad is ONGC Videsh Ltd. (OVL), the overseas investment arm of ONGC. OVL conducts oil and natural gas operations in 13 countries, including Vietnam, Myanmar, Russia (Sakhalin Island), Iran, Iraq, Sudan, Brazil, and Columbia. One of OVL’s most high profile investments is its share in the Greater Nile Petroleum Operating Company (GNPOC), which has engaged in E&P work in Sudan since 1997. OVL acquired a 25 percent equity stake in the company in 2003, with the balance held by the China National Petroleum Company (CNPC, 40 percent), Petronas (30 percent), and the Sudan National Oil Company (Sudapet, 5 percent). The GNPOC acreage in Sudan holds proved crude oil reserves of more than one billion barrels with current production levels at roughly 300,000 bbl/d from 10 fields. In addition to the upstream activities, the GNPOC companies operate a 935-mile crude oil pipeline that pumps oil to Port Sudan for export.

OVL also holds a 20 percent stake in the ExxonMobil-led consortium that operates the Sakhalin-I project in Russia. According to company estimates, the oil fields associated with Sakhalin-I hold recoverable crude oil reserves of 2.3 billion barrels.

In addition to ONGC, other Indian companies are also actively involved in E&P projects abroad. OIL, for example, is working on projects in Libya, Gabon, Nigeria, and Sudan.

Downstream/Refining

According to OGJ, India had 2.8 million bbl/d of crude oil refining capacity at 18 facilities as of January 1, 2010. India has the fifth largest refinery capacity in the world. In 2009, privately-owned Reliance Industries added another refinery to its Jamnagar complex to raise the entire complex’s refining capacity from 660,000 bbl/d to 1.24 million bbl/d. The Jamnagar complex is the largest oil refinery complex in the world.

Other key upcoming refinery projects include Essar Oil’s Vadinar refinery expansion of 110,000 bbl/d in 2011, 120,000 bbl/d greenfield refinery in Bina in 2011 by a joint venture between Bharat Petroleum Corporation Limited and Oman Oil Company Limited, a 180,000 bbl/d grassroots refinery in Bhatinda in 2014 by Hindustan Petroleum Corporation Limited, and IOC’s grassroots Paradeep refinery of 300,000 bbl/d in 2015. India is slated to add 840 thousand bbl/d of refining capacity through 2015 based on currently proposed projects.

Due to expectations of higher demand for petroleum products in the region, further investment in the Indian refining sector is likely. As part of the country’s 11th Five Year Plan from 2007 to 2012, the government would like to promote India as a competitive refining destination, and industry experts expect the country to be an exporter of refined products to Asia in the near future.

Refined Fuel Subsidies

The Market Determined Price Mechanism is notionally benchmarked to international oil prices, but the Indian government heavily subsidizes domestic prices of oil products such as diesel, gasoline, kerosene, and LPG. At the same time, taxes on crude and petroleum products imposed by different layers of Indian government often exceed the subsidies. According to industry analysts, though originally an attempt to protect economically disadvantaged Indian consumers, fuel subsidies distort India’s domestic market by forcing India’s state owned oil companies to accept “under-recoveries” (i.e. losses) and encouraging India’s private companies to orient their product sales internationally. With diesel prices significantly lower than other fuels, particularly gasoline, diesel consumption rose by nearly 20 percent from 2007 through 2009. The International Energy Agency reports that losses from fuel price subsidies for the 2010-11 fiscal year are expected to exceed $23 billion.

Strategic Petroleum Reserve

To support India’s energy security, India is constructing a strategic petroleum reserve (SPR). The first storage facility at Visakhapatnam will hold approximately 9.8 million bbls of crude (1.33 million tons) and is scheduled for completion by the end of 2011. The second facility at Mangalore will have a capacity of nearly 11 million bbls (1.5 million tons) and is scheduled for completion by the end of 2012. The third facility of Padur, also scheduled to be completed by the end of 2012, will have a capacity of nearly 18.3 million bbls (2.5 million tons).

The selection of coastal storage facilities was made so that the reserves could be easily transported to refineries during a supply disruption. The SPR project is being managed by the Indian Strategic Petroleum Reserves Limited (ISPRL), which is part of Oil Industry Development Board (OIDB), a state-controlled organization. India does not have any strategic crude oil stocks at this time.

Natural Gas

According to Oil and Gas Journal, India had approximately 38 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2010. The EIA estimates that India produced approximately 1.4 Tcf of natural gas in 2009, a 20 percent increase over 2008 production levels. The bulk of India’s natural gas production comes from the western offshore regions, especially the Mumbai High complex, though the Bay of Bengal and its Krishna-Godavari (KG) fields are proving quite productive. The onshore fields in Assam, Andhra Pradesh, and Gujarat states are also significant sources of natural gas production.

In 2009, India consumed roughly 1.8 Tcf of natural gas, almost 300 billion cubic feet (Bcf) more than in 2008, according to EIA estimates. Natural gas demand is expected to grow considerably, largely driven by demand in the power sector. The power and fertilizer sectors account for nearly three-quarters of natural gas consumption in India. Natural gas is expected to be an increasingly important component of energy consumption as the country pursues energy resource diversification and overall energy security.

Despite the steady increase in India’s natural gas production, demand has outstripped supply and the country has been a net importer of natural gas since 2004. India’s net imports reached an estimated 445 Bcf in 2009.

Sector Organization

As in the oil sector, India’s state-owned companies account for the bulk of natural gas production. State-run companies Oil and Natural Gas Corporation (ONGC) and Oil India Ltd. (OIL) are the main producers of natural gas in the country. According to government statistics, ONGC accounted for 69 percent of natural gas production in the country in 2007. In addition, some foreign companies participate in upstream developments in joint-ventures and production sharing contracts (PSCs). Privately-owned Reliance Industries will also have a greater role in the natural gas sector in the coming years, as a result of a large natural gas find in 2002 in the KG basin.

Natural gas prices in India are regulated by the government. Administered Pricing Mechanism (APM) natural gas, gas produced from fields handed to ONGC and OIL by the Indian government, more than doubled in price in May 2010; from $1.8/million (MM)Btu to $4.2/MMbtu. This price adjustment brings APM gas, formerly the cheapest gas in India, to parity with the KG-D6 natural gas (see below). Gas produced from fields acquired through the National Export Licensing Policy (see oil section), production sharing agreements, and imported LNG is not priced using the APM, although its price is also regulated.

The Gas Authority of India Ltd. (GAIL) holds an effective monopoly on natural gas transmission and distribution activities. In December 2006, the Minister of Petroleum and Natural Gas issued a new policy that allows foreign investors, private domestic companies, and national oil companies to hold 100 percent equity stakes in pipeline projects. While GAIL’s monopoly in natural gas transmission and distribution is not guaranteed by statute, it is the de facto leading player in the sector because of its existing natural gas infrastructure.

GAIL’s current natural gas trunk pipeline network extends roughly 4,100 miles, according to the company, and its transmission capacity is approximately 5.2 Bcf/d. GAIL plans to build close to 3,800 additional miles of pipelines by 2012, bringing its total transmission capacity to 10.6 Bcf/d.

Exploration and Production

The outlook for India’s upstream natural gas sector is more positive than its upstream oil sector, although the IEA forecasts Indian natural gas peak production between 2020 and 2030.

There have been several large natural gas finds in India over the last several years, predominantly offshore in the Bay of Bengal. ONGC announced a find in late 2006 in the Mahanadi basin off the coast of Orissa state, with an estimated 3 to 4 Tcf of reserves in place. In December 2006, ONGC announced a find of an estimated 21 to 22 Tcf of natural gas in place at the KG-DOWN-98/2 block off the coast of Andhra Pradesh in the KG basin. In addition, state-owned Gujarat State Petroleum Corporation (GSPC) holds an estimated 1.8 Tcf of natural gas reserves at the KG-OSN-2001/3 block in the KG area.

Reliance Industries’ KG-D6 block holds estimated reserves of 11.5 Tcf and came online in April 2009. Of the nearly 1.4 Bcf/d of initial production, nearly half went to gas based power plants, the rest to fertilizer, LPG plants, and city gas distribution entities. After reaching a production peak of 2.8 Bcf/d in December 2009, Reliance decided in July 2010 to cap production of KG-D6 at 2.1 Bcf/d pending resolution of infrastructure and field maintenance issues. The power sector continues to receive the lion’s share of production allotments. Production from the KG basin is expected to double the country’s current natural gas output in coming years.

Natural Gas Imports

India’s natural gas import demand is expected to increase in the coming years. To help meet this growing demand, a number of import schemes including both LNG and pipeline projects have either been implemented or considered.

Iran-Pakistan-India Pipeline

India has considered various proposals for international pipeline connections with other countries. One such scheme is the Iran-Pakistan-India (IPI) Pipeline, which has been under discussion since 1994. The plan calls for a roughly 1,700-mile, 5.4-Bcf/d pipeline to run from the South Pars fields in Iran to the Indian state of Gujarat. While Iran is keen to export its abundant natural gas resources and India is in search of projects to meet its growing domestic demand, a variety of economic and political issues have delayed a project agreement. Indian officials have made it clear that any import pipeline crossing Pakistan would need to be accompanied by a security guarantee from officials in Islamabad. Due to the uncertainties involving this pipeline, the Indian government’s 11th Five Year Plan does not project any gas supply from this route or the following two discussed pipelines.

Turkmenistan-Afghanistan-Pakistan-India Pipeline

India has worked to join the Turkmenistan-Afghanistan-Pakistan Pipeline (TAP or Trans-Afghan Pipeline). With the inclusion of India, the project consists of a planned 1,050-mile pipeline originating in Turkmenistan’s Dauletabad natural gas fields and transporting the fuel to markets in Afghanistan, Pakistan, and India. In 2008, all parties agreed to induct India as a full member into the project, thereby renaming the pipeline TAPI. TAPI is envisioned to have a capacity of 3.2 Bcf/d, but work has not yet begun on the project. Concerns about the project have included the security of the route, which would traverse unstable regions in Afghanistan and Pakistan. Furthermore, a review of the TAPI project raised doubts as to whether Turkmen natural gas supplies are adequate to meet proposed export commitments.

Imports from Myanmar

A third international pipeline proposal envisions India importing natural gas from Myanmar. In March 2006, the governments of India and Myanmar signed a natural gas supply deal. Initially, the two countries planned to build a pipeline crossing Bangladesh. After indecision from Bangladeshi authorities over the plans, India and Myanmar studied the possibility of building a pipeline that would terminate in the eastern Indian state of Tripura and not cross Bangladeshi soil. In March 2009, Myanmar signed a natural gas supply deal with China sourced from a field invested in by GAIL and ONGC, putting any India-Myanmar pipeline deal in question.

Liquefied Natural Gas

India began importing liquefied natural gas (LNG) in 2004. In 2008, India imported 372 Bcf of LNG, nearly 75 percent of it from Qatar, making it the sixth largest importer of LNG in the world. India imports LNG through both long-term contracts and spot shipments.

Currently, India has two operational LNG import terminals, Dahej and Hazira. India received its first LNG shipments in January 2004 with the start-up of the Dahej terminal in Gujarat state. Petronet LNG, a consortium of state-owned Indian companies and international investors, owns and operates the Dahej LNG facility with a capacity of 5 million tons per year (mtpa) (975 Bcf/y). India’s second terminal, Hazira LNG, started operations in April 2005, and is owned by a joint venture of Shell and Total. The facility has a capacity of 2.5 mtpa (488 Bcf/y), which may be expanded to 5 mtpa (975 Bcf/y) in the future.

The 5 mtpa (975 Bcf/y) LNG processing plant in Dabhol continues to face delays. Currently operating as a power plant, the LNG receiving terminal may be operational in 2011 after dredging operations are complete so that a breakwater can be built.

In addition, Petronet LNG has begun construction of a 2.5 mtpa (488 Bcf/y) LNG import facility at Kochi. The facility is expected to be completed in the first quarter of 2012 and has secured a 1.5 mtpa (293 Bcf/y) supply from Australia’s Gorgon LNG project.

In order to secure supply of natural gas to India and meet growing demand, India is currently looking to invest in liquefaction projects abroad. For example, ONGC and the UK-based Hinduja Group are considering service contracts in Iran to supply 5 mtpa (975 Bcf/y) of LNG to India. The country is also exploring the possibility of investing more in the Sakhalin I LNG project.

Long-term growth in demand for LNG remains unclear however, as price is an issue of contention in India and increasing domestic natural gas production is expected from eastern offshore fields. Industry analysts note that Indian companies appear unwilling to commit to long-term LNG supply contracts at international prices. While negotiations are currently underway for several long-term LNG supply deals, whether or not India’s bids will be accepted is questionable in light of the low prices that India has offered to pay. Instead, India is becoming an important destination for spot LNG cargoes. {jcomments on}
Ecuador Energy Profile: Country Fails To Benefit From High Oil Prices
miércoles, 01 de septiembre de 2010 11:27

Ecuador is one of Latin America’s largest oil exporters, with net oil exports estimated at 305,000 barrels per day (bbl/d) in 2009. The oil sector accounts for about 50 percent of Ecuador’s export earnings and about one-third of all tax revenues. Despite being an oil exporter, Ecuador  must still import refined petroleum products due to the lack of sufficient domestic refining capacity to meet local demand. As a result, the country does not always enjoy the full benefits of high world oil prices: while these high prices bring Ecuador greater export revenues, they also increase the country’s refined product import bill.

In 2007, Ecuador re-joined the Organization of the Petroleum Exporting Countries (OPEC), after leaving the organization at the end of 1992. Ecuador is the smallest oil producer in OPEC, with an assigned production quota of 434,000 bbl/d. OPEC quotas combined with an uncertain investment climate have had a negative impact on international investments and oil production, severely impacting Ecuador’s economy. In this climate, government budget support has come in the form of Chinese oil-backed loans, whereby the Chinese government provides infrastructure loans in exchange for oil contracts (often at a discount to market prices).

Total energy consumption by type

Ecuador’s energy mix is largely dependent upon oil, which represented close to 80 percent of the country’s total energy consumption in 2007. Hydroelectric power represented 19 percent of total energy consumption in 2007, and accounts for about half of all generated electricity. Natural gas consumption is minimal, due to the lack of domestic infrastructure to transport, distribute and utilize the fuel. While urban electrification rates are close to 100 percent, droughts in late 2009, affecting the Paute River hydroelectric plant, caused the government to implement electricity rationing from November 2009 to January 2010.

Oil

According to Oil and Gas Journal (OGJ), Ecuador held proven oil reserves of 6.5 billion barrels in January 2010 – a  significant increase from 2009 estimates of 4.7 billion barrels, and the  third largest reserves in South America after Venezuela and Brazil. Ecuador is the fifth-largest producer of oil in South America, producing  486,000 bbl/d of oil in 2009 (almost all of which was crude oil), down  from 2006 highs of 536,000 bbl/d and decreasing – first half 2010 data  indicate that Ecuador’s average oil production was 470,000 bbl/d.

In 2009, Ecuador consumed 181,000 bbl/d of oil, leaving 2009 net exports of 305,000 bbl/d. Ecuador sends about 60 percent of its oil exports to the United States, the remainder split between Latin America and Asia. In 2009, Ecuador exported 185,000 bbl/d of oil to the United States, accounting for less than two percent of total U.S. oil imports.  Other major destinations for Ecuadorian crude in 2009 were Chile, Peru and China.  Ecuador has begun to look more towards the Asian market, namely China, as a way to diversify its oil investment and trade.

Since 2009, Ecuador has agreed to two separate oil-backed loan agreements with China.  Under these agreements, Ecuador is required to invest a share of the loaned amount in infrastructure  projects involving Chinese companies and repay the loans in fixed-price  crude oil shipments.  In 2009, Chinese oil imports from Ecuador totaled 36,000 bbl/d, 12 percent of Ecuador’s total oil exports, an increase from the previous year’s 21,000 bbl/d.

Sector Organization

Petroecuador,  the state-run oil company, controls most of the crude oil production in  the country. The largest foreign-owned oil company is Repsol-YPF,  followed by Andes Petroleum, a consortium led by the Chinese National  Petroleum Corporation (CNPC) that acquired assets in September 2005  formerly owned by EnCana.  Other international companies operating in Ecuador include Italy’s Eni, Brazil’s Petrobras, Chile’s Enap and Petroriental of China.

In August 2010, oil companies were reportedly provided with new  contract models under the new Hydrocarbon Law and have been given until  the end of the year to agree to negotiate the new terms or leave Ecuador.   This process is designed to increase the Ecuadorian government’s share  of oil revenue by transforming existing contracts with foreign oil  companies into service agreements. Under the latest contract terms, all  oil production will be considered state property and oil companies will  act as an agent that produces oil on behalf of the state, receiving a  flat fee as compensation.

Petroecuador and the Ecuadorian government have, in recent years,  appropriated the assets of international oil companies.  In 2006, the  company took over the production assets of Occidental Petroleum as a  result of expired contracts and in 2009, following a tax dispute, the  government also appropriated two blocks belonging to Perenco.

Exploration and Production

Ecuador’s  most productive oil fields are located in the northeast corner of the  country. The largest oil field is Shushufindi. Other major oil fields  include Sacha, Libertador, Dorine, and Eden Yuturi. Production has  fallen in recent years due to lower investment levels, leading to higher  decline rates from existing fields. Ecuador produces two varieties of crude oil: Oriente and Napo.  Both are heavy sour crudes with APIs of 19° and 24°, respectively, and sulfur contents of 1 and 2 percent.

Crude oil production increased sizably in 2003 with the opening of  the Oelducto de Crudos Pesados (OCP), which removed a chokepoint on  crude oil transportation in the country (see below). However, production  has fallen in recent years, the result of natural decline, the lack of  new project development, and some operating difficulties at existing oil  fields.

Future increases in Ecuador’s crude oil production will likely come from development of the Ishpingo-Tapococha-Tiputini (ITT) block located in the Yasuni National Park in the Amazon Region. The ITT block contains an estimated 850 million  barrels of proven reserves, with potential recoverable reserves as high  as 1.3 billion barrels. Analysts predict that, if fully developed, the  block could produce at least 190,000 bbl/d. However, the ITT block  reportedly contains a variety of crude oil even heavier than Napo, so  any oil producer would need to blend the crude with lighter hydrocarbons  before shipping it via Ecuador’s pipeline network.

As an alternative to the development of the ITT block, the government of Ecuador in 2010 signed an agreement with the United Nations Development Program  (UNDP) where the international community will agree to pay US$ 350  million a year for 10 years for not developing the ITT field.  Uncertainty remains regarding the status of this agreement and plans to  develop the field.

Pipelines

Ecuador has two major oil pipeline systems. The first is the Sistema Oleducto  Trans-Ecuatoriano (SOTE), built in the early 1970s. The 310-mile,  400,000-bbl/d SOTE runs from Lago Agrio to the Balao oil terminal on the  Pacific coast. SOTE has suffered from natural disasters that severely  disrupted Ecuador’s  oil production. In March 2008, landslides damaged SOTE, shutting  operations for several days. In 1987, an earthquake destroyed a large  section of SOTE, reducing Ecuador’s oil production for that year by over 50 percent.

The second oil pipeline is the Oleducto de Crudos Pesados (OCP).  The 300-mile, 450,000-bbl/d OCP mostly parallels the route of the SOTE.  The OCP began operations in September 2003, and its completion  immediately doubled Ecuador’s oil pipeline capacity. The completion of the OCP pipeline led to a sharp increase in Ecuador’s  crude oil production, as private companies were no longer constrained  by the capacity limits of the SOTE. Use of the OCP system is mostly  confined to private oil producers, with Petroecuador relying upon SOTE.

Ecuador utilizes one international pipeline, the TransAndino. The 50,000-bbl/d pipeline connects Ecuador’s oil fields with the Colombian port of Tumaco. The TransAndino pipeline has occasionally been the target of rebel forces in Colombia, and an attack in March 2008 shut the system down for several days.

Downstream Activities

According to OGJ, Ecuador has three oil refineries, with a combined capacity of 176,000 bbl/d. The largest refinery in Ecuador is Esmeraldas (110,000 bbl/d), located on the Pacific coast. Despite its status as a crude oil exporter, Ecuador is a net importer of refined oil products. In general, Ecuador exports heavy refined products, like fuel oil, and imports lighter  products, such as gasoline, diesel, and liquefied petroleum gas (LPG).  Since the heavy product exports command a much lower price on the world  market than Ecuador must pay for the light product imports, the value of the net trade  balance is more skewed than would be suggested by simply comparing  import and export volumes. This can lead to situations where the country  is unable to fully take advantage of higher world oil prices, because  these higher prices might increase their product import bill by a  greater amount than their crude oil export revenues. According to DownstreamToday, the government spends about US$ 3 billion annually on imports of refined products, mainly gasoline and diesel.

Given these imbalances, Ecuador has, in recent years, established “barter” agreements with neighboring countries.  In 2009, Petroecuador and Chile’s Enap reportedly signed a deal where Ecuadorian crude would be provided to Chile in exchange for refined products.  A similar agreement was signed with Uruguay’s Ancap in March 2010.

The Ecuadorian government is actively seeking ways to increase  domestic production of lighter petroleum products. These plans include  upgrading the Esmeralda refinery and building new refining facilities to  better handle Ecuador’s heavy domestic crude production. In late 2008, Ecuador signed a contract with South Korea’s  SK Engineering to repair, overhaul and upgrade the Esmeraldas refinery  which is currently underway. The refinery went into emergency conditions  in August 2010 following a major oil leak, reportedly caused by poor  maintenance and old infrastructure.

There have also been discussions between Ecuador and Venezuela about the construction of a new refinery in Ecuador. The two countries established a joint company in mid-2008 to build the facility on the Pacific Coast in Manabi province. The planned crude distillation capacity of the  refinery is 300,000 bbl/d. Construction is expected to begin in 2010 and  startup is scheduled for 2013.

Natural Gas

According to OGJ, Ecuador had 282 billion cubic feet (Bcf) of natural gas reserves as of January 2010. In 2008, Ecuador produced total of 44 Bcf of natural gas, almost all of which was  associated gas from oil production, with the exception of the Amistad  field discussed below.  Of the gross 44 Bcf produced, 27 Bcf was vented  or flared, 8 Bcf was reinjected to enhance oil recovery and only 9 Bcf  was marketed.  The low natural gas utilization rates are due mainly to  the lack of infrastructure to capture and market natural gas.

The only large-scale natural gas project in Ecuador is the Amistad field, located in the Gulf of Guayaquil,  which is producing an estimated 22 million cubic feet per day (MMcf/d)  in 2010. All of Amistad’s natural gas production flows to Noble’s  Machala facility, a 130-megawatt (MW), onshore, gas-fired power plant  that supplies electricity to the Guayaquil region.

Other efforts to develop natural gas reserves in the Gulf of Guayaquil include plans by Chile’s Enap and Venezuela’s PdVSA to work with Petroecuador to explore additional blocks in the area.

EIA

EIA

The U.S. Energy Information Administration (EIA) collects, analyzes, and disseminates independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment.

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