Agip North Africa & Middle East.

Agip, an operator in Libya since 1959, has a number of blocks where it is exploring for oil and gas. It produces about 160,000 b/d from Bu Attifel and Rimal-Khatib groups onshore and el-Bouri offshore. But their sustainable capacity is 180,000 b/d. Agip NAME is a 100% Channel Islands part of ENI. In June 2008, when paper WTI was trading at $140/b, it signed an agreement on EPSA-IV terms extending ENI's concessions for another 25 years.

ENI was the first IOC to agree to EPSA-IV terms in 2007, when it signed an initial accord whereby the group pledged to invest $28 bn in oil and gas E&P projects with emphasis on natural gas and a proposed major LNG export venture. Now ENI's total production in Libya amounts to more than 550,000 b/doe of crude oil and natural gas, and its net share is 250,000 b/doe - accounting for 14% of its total output.

After an agreement between visiting PM Silvio Berlusconi and Libyan ruler Mu'ammar Qadhafi in 2008, the Italian government agreed to give Tripoli a 3.9bn ($5bn) in compensation for Italy's 1911-43 occupation of Libya. This is under a friendship pact ratified in March 2009 whereby Rome will pay the sum in return for Libya cracking down on illegal immigration to Italy. Rome then issued a law compelling ENI to fund this amount. In April 2009, ENI appealed against the law. Petroleum Argus on May 4 quoted ENI's CFO Alessandro Bernini as saying: "We expect [to pay] 288m over the whole year. In the first quarter, the surcharge affected our bottom line by about 70m". ENI was to pay the sum over 20 years in 280m instalments for the first three years, and 180m thereafter. An Italian court is expected to decide on the appeal by end-2009.

Agip NAME's capacity has fallen from 320,000 b/d in 1992, because it was not able to import adequate EOR equipment. But this excludes Agip's (Lasmo's) Murzuk Basin operations. The worst affected was the Bu Attifel field, a giant requiring a water injection system because reservoir pressure has been falling since 1994. It is said that even if it manages to install an advanced EOR system at Bu Attifel, Agip's sustainable capacity is not likely to change much in the near future; but it would prevent a major fall in reservoir pressure. Bu Attifel, found in 1968 at 14,300 ft on the eastern side of the Sirte Basin, was put on stream in late 1970. One of the deepest fields in Libya, it produces 41? API oil (see gmt2LibFieldsJuly9-07).

Under a deal signed in 1993, Agip has developed of gas-rich offshore Block NC-41, adjacent to el-Bouri, along with el-Bouri's gas reserves and an onshore gas field called al-Wafa'. Offshore NC-41, north-west of Tripoli called Bahr Essalam which contains oil, has a Pelagian Fm with characteristics partly similar to those of el-Bouri. Al-Wafa', found in 1991 by Sirte Oil Co., straddles the border with Algeria in the Ghadames Basin and is an extension of Algeria's Alrar gas field. Combined, this system now is producing over 11 BCM/year. Of this, 8 BCM/y are exported to Sicily through a marine pipeline. The rest is consumed in Libya. This 7.4 bn Western Libya Gas Project (WLGP) is a JV of Agip Gas BV and NOC. Related to it is the export pipeline JV called Greenstream. With al-Wafa' development completed ahead of schedule, Greenstream was inaugurated on Oct. 7, 2004, in a ceremony attended by Qadhafi and Berlusconi (see gmt3LibGasExprtJul20-09).

Apart from the 11 BCM/y gas stream, the whole WLGP completed in 2005 produces 60,000 b/d of crude oil, 39,000 b/d of condensates, about 15,000 b/d of propane and 13,000 b/d of butane (see background in gmt2LibFieldsJul11-05).

Agip boosted its position in Libya with its takeover of Lasmo in December 2000. This gave Agip a stake in the giant Elephant oilfield in the onshore Murzuk Basin which went on stream in January 2004.

Agip (Lasmo) has developed Elephant, on Block NC-174, which at present is producing 130,000 b/d but has a capacity of 150,000 b/d. ENI, through Lasmo and Agip, holds 33.3% in this. NOC has 50% and a group of South Korean companies hold the remainder. ENI hopes the output could rise to 200,000 b/d by 2015 and eventually reach 300,000 b/d. The same partners have Block NC-173 in a nearby section of the Gulf of Sirte.

Elephant's output now has its own 740-km crude oil pipeline from al-Sharara to Mellita completed in 2006 with a capacity of 150,000 b/d, later to be expanded.

Petro-Canada of Calgary produces 70,000 b/d and has a capacity of 90,000 b/d in Libya which by 2013 will have a capacity of 100,000 b/d. The output comes of En Naga field, in Sirte Basin's Block-177 which it purchased in 2001 from Lundin Oil of Sweden, and from a number of fields which it got in January 2002 after its acquisition of Veba Oil & Gas of Germany from BP.

It was announced on March 22, 2009, that Suncor Energy agreed to buy PetroCanada for about C$17 bn to diversify and gain assets in the North Sea, North Africa and Latin America. Suncor is the world's second-largest oil-sands producer. It was then said that Suncor's purchase of PetroCanada, Canada's second biggest refiner, was to create Canada's biggest energy company and help it reduce reliance on high-cost oil-sands mines after crude oil prices fell sharply from paper WTI's peak of $147.27/b on July 11, 2008.

En Naga went on stream in March 2003 at the rate of 6,800 b/d. This rose to a plateau of 24,000 b/d in early 2004. En Naga crude is pumped to the Samah oilfield complex via a 100-km pipeline. The field contains 85m barrels.

The operation acquired from Veba involve several small fields and the mature giant Amal which is depleting rapidly. Their total output had fallen from 85,000 b/d in 1992 (see Vol. 57, Gas Market Trends No. 2).

Al-Harruj Petroleum Operations (HPO), a JV of PetroCanada and NOC, in 2007 embarked on EOR projects. This is for Amal and the other fields.

Wintershall, a unit of the German petrochemical giant BASF, operates nine oilfields in Blocks NC-96 and NC-97 in the Sirte Basin. Their combined output averages 100,000 b/d and their capacity is 120,000 b/d. But these fields are depleting and their capacity is expected to fall to 100,000 b/d in the coming years.

Its biggest field is as-Sarah in the Jakhira zone, 450 km south-east of Benghazi, which it found in January 1989 in Block NC-96. The field's reserves were then estimated at about 250m barrels.

As part of an assets swap deal between BASF and the Russian gas giant Gazprom, the Kremlin-controlled group in late 2007 acquired a 49% stake in Blocks NC-96/NC-97. This was approved by NOC.

On its own, Gazprom has acquired important acreage in Libya and intends to invest heavily in this country. With bilateral relations handled directly between Qadhafi and each of Russia's PM Vladimir Putin and President Dmitry Medvedev, Gazprom and other Russian companies are to have a high profile in Libya.

Earlier this year, Gazprom Chairman/CEO Alexei Miller visited Tripoli at the head of a large delegation and agreed with NOC Chairman Dr Ghanem for the two companies to invest jointly in Libya and Russia as well as in other country. At one time, Gazprom offered to buy all of Libya oil and gas exports (see gmt10RusOverseas-Sep1-08).

As part of a developing alliance between the two countries, Russia is to have a naval base in Libya and Tripoli is negotiating with Moscow the purchase of advanced defence systems.

Total - whose operations in Libya now are under the name of Mabruk Oil - produces 40,000 b/d of crude oil and its capacity is 50,000 b/d. This is to be expanded to 70,000 b/d in the coming years, down from a target of 110,000 b/d originally set for 2009.

Total's production comes from the onshore Mabruk field in Block C-17 in the Sirte Basin, and from al-Jurf field in the offshore Block NC-137 of the Sabratha Basin around 100 km from the Libyan coast and 160 km north-west of Tripoli. Al-Jurf Phase-1 development was completed in the March 2008. Al-Jurf's operations were stopped in April 2008 because of an accident and were resumed in January 2009.

Mabruk was found in 1959 by Exxon. It was left undeveloped for over three decades because of its highly-fractured nature, low-pressure reservoir and low oil-gas ratio. Development costs were then estimated at $1 bn. The field's reserves were then put at 1.3 bn barrels of 35-40? API oil.

Total signed an accord with NOC in late 1993 to develop the field. It brought on stream in June 1995 a pilot EOR system based on water injection, enabling the field to produce at 2,000 b/d. This has since risen steadily.

Al-Jurf consists of a fixed platform with 10 production wells connected to a floating production storage offloading (FPSO) vessel. The FPSO has a storage capacity of more than 900,000 barrels.

Al-Jurf came on stream early in 2003. The FPSO vessel, the Farwah, was built by Izar of Spain for Exmar of Belgium and leased to Total for 12 years. The vessel, delivered in early 2003, is linked to the platform in 90 metres of water.

The offshore field, found in 1975 by Total and confirmed in 1998, is about 100 km off the coast near the Tunisian border. It produces 38? API oil. Its partners in this are NOC and Wintershall. The field's

wells in 2003 indicated that about 150-200m barrels of oil would be recoverable.

In late July 2006, Total announced its first discovery in Block NC-191 in the southern Murzuq basin. The 1,735-metre deep D1 well tested at 675 b/d. Appraisal of the discovery and of the potential of the block, for which Total signed an EPSA in May 2001, indicated that the field's coverable reserves of about 100m barrels. But NOC's final approval of Total's plan to develop this field came in late 2008, after long delays. Total is hoping to bring it on stream in 2010 and add it to its production system.

Total in the first week of February 2009 announced the signature of an MoU with NOC converting its contracts for Blocks C17 and C137 to the EPSA-IV format. Total then had a 75% working interest of the "Second Party share" in each block, with StatoilHydro holding 25% of Block C17 and Wintershall 25% of Block C137. Total then said it took the opportunity to "reinvigorate" its investment policy in Libya and position itself as a strategic and privileged partner over the long term. But with NOC taking 50% in all foreign-operated JVs, the real equity of Mabruk Oil's foreign partners translates into half of the operating interest

In May 2009, Total had to renegotiate its contract for al-Jurf after NOC cut the French major's equity in the field to 30%. The field is said to have the potential of producing over 40,000 b/d of crude oil.

In June 2009, Total issued a tender for an offshore environmental study for al-Jurf's Phase-2 development. Mabruk Oil was in early July reported to be planning to invite local and international offshore contractors to complete the study, although it had yet to set a deadline for companies to submit pre-qualification documents.

In 2008, Total's equity production in Libya, including its interests in non-operated blocks in Libya, averaged around 75,000 b/d of crude oil.

In addition to production from the offshore al-Jurf field and from the Mabruk field in Block C17, Total operates a number of other exploration licences in Libya.

OMV of Austria has been in Libya since 1985, when it bought 25% of Oxy's operations for $110m. These included Oxy's oil-rich Blocks 102 and 103 in the Sirte Basin of Zuetina Oil Co. (see omt2LibFieldJuly13-09)

After Oxy left Libya in June 1986, OMV raised its E&P stake in this country by taking additional acreage (see Vol. 57, Gas Market Trends No. 2).

In 2007, OMV was to drill 13 exploration wells in Libya. The Austrian major has E&P operations in neighbouring Tunisia, where it produces oil and gas, and has upstream interests in Algeria and Egypt. It is operating in Iran and has oil E&P interests Iraq's Kurdistan.

OMV's own crude output now averages only about 10,000 b/d from several small fields in the Sirte and Ghadames Basins, down from 40,000 b/d in 1992.